From e5263e61177a2c0994e29cb66bbb8b3e17c0b363 Mon Sep 17 00:00:00 2001 From: Dwight Gunning Date: Wed, 30 Sep 2026 11:15:38 -0400 Subject: [PATCH] fix(documents): keep both items of a combined "Items 1 and 2" heading When a 10-K's TOC link text is a combined heading ("Items 1 and 2. Business and Properties", "Items 1. and 2.", "Items 1. and 2.", "Items 7. and 7A."), every TOC parser (Workiva, Donnelley, generic) dropped the row: _item_label_from_text matches `item\s+(\d+)`, and the plural's "s" fails it. The keyword fallback matched nothing, and since 5.34.0's per-form schema the generic path returns "" for unmatched text instead of the raw title that used to become a part_i_items_1_and_2_... key. Part I then started at Item 1A and tenk.business was None on Viper (broken since 5.29.0, the Workiva parser), Devon (5.34.0), Freeport and Cheniere. The #710 test injected ready-made keys, so it never exercised detection. - toc_analyzer: a combined label reads as its first item (TOCAnalyzer.combined_item_numbers). - Section.covered_items (new): both items, read from the section's own heading within its first 5,000 chars. Viper's TOC link lands on a 2,681-char preamble ahead of the heading, and Talos's TOC splits the label and link across cells. - TenK.__getitem__ / .items resolve the second item to that section. - The pattern-augmentation gate counts covered items as found, so a bare "Properties" sub-heading inside Talos's Item 1 no longer becomes a 1,311-char Item 2 (#1383). Verified offline on four real filings (new fixtures vnom, lng, fcx, talo) and live on Devon. Fast lane: 7,799 passed; the one failure (test_dt1f1_wrapped_item_headers 20-F lengths) fails identically on main. All 60 section network regression files pass, one file per call, and the parity and corpus ratchets pass (35) with the new fixtures in the corpus. Co-Authored-By: Claude Opus 5.5 --- changelog.d/1382.fixed.md | 1 + edgar/ai/skills/reports/skill.yaml | 5 + edgar/company_reports/ten_k.py | 19 +- edgar/documents/document.py | 6 +- .../extractors/hybrid_section_detector.py | 12 +- .../extractors/toc_section_detector.py | 34 +- edgar/documents/utils/toc_analyzer.py | 32 + .../html/fcx/10k/fcx-10-k-2025-02-14.html | 8 + .../html/lng/10k/lng-10-k-2026-02-26.html | 8 + .../html/talo/10k/talo-10-k-2026-02-25.html | 13705 ++++++++++++++++ .../html/vnom/10k/vnom-10-k-2026-02-25.html | 8 + .../test_issue_1382_combined_item_headings.py | 144 + 12 files changed, 13975 insertions(+), 7 deletions(-) create mode 100644 changelog.d/1382.fixed.md create mode 100644 tests/fixtures/html/fcx/10k/fcx-10-k-2025-02-14.html create mode 100644 tests/fixtures/html/lng/10k/lng-10-k-2026-02-26.html create mode 100644 tests/fixtures/html/talo/10k/talo-10-k-2026-02-25.html create mode 100644 tests/fixtures/html/vnom/10k/vnom-10-k-2026-02-25.html create mode 100644 tests/issues/regression/test_issue_1382_combined_item_headings.py diff --git a/changelog.d/1382.fixed.md b/changelog.d/1382.fixed.md new file mode 100644 index 000000000..5bb0f7def --- /dev/null +++ b/changelog.d/1382.fixed.md @@ -0,0 +1 @@ +**`TenK` keeps both items of a combined heading such as "Items 1 and 2. Business and Properties".** A TOC link reading "Items 1 and 2" (or "Items 1. and 2.", "Items 7. and 7A.") was dropped, so `tenk.business` was None on Viper, Devon, Freeport and Cheniere. The section is now keyed as the first item, lists both in `Section.covered_items`, and answers for either. Talos no longer shows a 1,311-character "Properties" fragment as Item 2. (GH #1382, #1383) diff --git a/edgar/ai/skills/reports/skill.yaml b/edgar/ai/skills/reports/skill.yaml index ef7c25189..6a072fea5 100644 --- a/edgar/ai/skills/reports/skill.yaml +++ b/edgar/ai/skills/reports/skill.yaml @@ -29,6 +29,11 @@ patterns: tenk.items # List: ['Item 1', 'Item 1A', 'Item 2', ...] + # Combined headings ("Items 1 and 2. Business and Properties") are ONE section, + # keyed as the first item; both items return it. + tenk['Item 2'] == tenk.business # True when the filer combines Items 1 and 2 + tenk.sections['part_i_item_1'].covered_items # ('1', '2'); () for a one-item section + tenk.auditor # AuditorInfo: .name .firm_id .location .icfr_attestation tenk.subsidiaries # SubsidiaryList from EX-21 (TenK only), .to_dataframe() tenk.reports # Reports from FilingSummary.xml (statements, notes, details) diff --git a/edgar/company_reports/ten_k.py b/edgar/company_reports/ten_k.py index cc6c35213..008eb2237 100644 --- a/edgar/company_reports/ten_k.py +++ b/edgar/company_reports/ten_k.py @@ -302,6 +302,8 @@ def _canonical(raw_items): # Check if section has an item attribute if hasattr(section, 'item') and section.item: items.append(f"Item {section.item}") + # "Items 1 and 2" is one section holding both (GH #1382) + items.extend(f"Item {item}" for item in getattr(section, 'covered_items', ())) # Map friendly names to Item numbers elif key in section_to_item: items.append(section_to_item[key]) @@ -596,9 +598,20 @@ def __getitem__(self, item_or_part: str): if text and text.strip(): return text - # PRIORITY 1.5: Try combined-items keys (e.g., "Items 1 and 2. Business and Properties") - # Some filings (energy, MLP, REIT) combine items under a single heading. - # Match whether the item is the first or second number: items_1_and_2 or items_2_and_3 + # PRIORITY 1.5: A section under a combined heading ("Items 1 and 2. + # Business and Properties") holds both items. Some filings (energy, + # MLP, REIT) combine items this way; the section is keyed as the + # first item and lists both in covered_items (GH #710, #1382). + if canonical_part: + for section in self.sections.values(): + covered = [item.lower() for item in getattr(section, 'covered_items', ())] + if item_num in covered and (section.part or '').lower() == canonical_part: + text = section.text() + if text and text.strip(): + return text + + # Legacy combined-items keys (part_i_items_1_and_2_...) from releases + # that built them from the heading text. inum = re.escape(item_num) combined_pattern = re.compile(rf'part_[iv]+_items_(?:{inum}_and_\d+|\d+_and_{inum})') for key in self.sections: diff --git a/edgar/documents/document.py b/edgar/documents/document.py index 668999b54..d4b529a45 100644 --- a/edgar/documents/document.py +++ b/edgar/documents/document.py @@ -6,7 +6,7 @@ import logging import re from dataclasses import dataclass, field -from typing import TYPE_CHECKING, Any, Callable, Dict, Iterator, List, Optional, cast +from typing import TYPE_CHECKING, Any, Callable, Dict, Iterator, List, Optional, Tuple, cast if TYPE_CHECKING: import pandas as pd @@ -111,6 +111,9 @@ class Section: validated: Whether section has been cross-validated part: Optional part identifier for 10-Q filings ("I", "II", or None for 10-K) item: Optional item identifier (e.g., "1", "1A", "2") + covered_items: Every item this section holds when the filer combines items + under one heading ("Items 1 and 2. Business and Properties" gives + ``('1', '2')``); empty for an ordinary one-item section _text_extractor: Optional callback for lazy text extraction (for TOC-based sections) _html_source: Optional HTML source for TOC-based table extraction _section_extractor: Optional section extractor for TOC-based sections @@ -129,6 +132,7 @@ class Section: _text_extractor: Optional[Any] = field(default=None, repr=False) # Callback for lazy text extraction _html_source: Optional[str] = field(default=None, repr=False) # HTML source for TOC table extraction _section_extractor: Optional[Any] = field(default=None, repr=False) # Section extractor for TOC sections + covered_items: Tuple[str, ...] = () # All items under a combined heading, e.g. ('1', '2') @property def kind(self) -> str: diff --git a/edgar/documents/extractors/hybrid_section_detector.py b/edgar/documents/extractors/hybrid_section_detector.py index 6eb7968f1..37ac096a7 100644 --- a/edgar/documents/extractors/hybrid_section_detector.py +++ b/edgar/documents/extractors/hybrid_section_detector.py @@ -195,9 +195,17 @@ def _augment_with_pattern_sections( # whose key string carries neither part nor item. canonical = {schema.resolve_section_key(key) for key in schema.section_patterns} canonical = {(part, item) for part, item in canonical if item} - found_items = {sec.item for sec in toc_sections.values() if sec.item} + # A section under a combined heading ("Items 1 and 2. Business and + # Properties") has found both items. Without this the gate saw Item 2 + # as missing and admitted a bare "Properties" sub-heading from inside + # Item 1 as a second, fragmentary Item 2 (Talos, GH #1383). + found_items = { + item for sec in toc_sections.values() + for item in (sec.covered_items or (sec.item,)) if item + } found_part_items = { - (sec.part, sec.item) for sec in toc_sections.values() if sec.item + (sec.part, item) for sec in toc_sections.values() + for item in (sec.covered_items or (sec.item,)) if item } if not canonical or canonical <= found_part_items: return toc_sections # The TOC named everything the form defines. diff --git a/edgar/documents/extractors/toc_section_detector.py b/edgar/documents/extractors/toc_section_detector.py index 01977ed02..f42218106 100644 --- a/edgar/documents/extractors/toc_section_detector.py +++ b/edgar/documents/extractors/toc_section_detector.py @@ -11,13 +11,44 @@ """ import logging -from typing import Dict, Optional +import re +from typing import Dict, Optional, Tuple from edgar.documents.document import Document, Section from edgar.documents.nodes import SectionNode +from edgar.documents.utils.toc_analyzer import TOCAnalyzer logger = logging.getLogger(__name__) +# The section's heading is near its start but not always first: Viper's TOC link +# lands on a 2,681-character preamble paragraph ahead of its "ITEMS 1 and 2." +# heading. A heading is a short line; prose that happens to open with "Items 1 +# and 2" is not. +_HEADING_SCAN_CHARS = 5000 +_HEADING_MAX_LEN = 250 # Freeport's "Items 7. and 7A." heading is 170 + + +def _covered_items(item: Optional[str], section_text: Optional[str]) -> Tuple[str, ...]: + """Both items of a section that opens on a combined "Items N and M" heading. + + The heading is the filer saying one span holds two items, so Item 2 of + "Items 1 and 2. Business and Properties" is this section, not something to + look for elsewhere (GH #1382, #1383). It is read from the section's own + opening lines, not the TOC row, because some TOCs split the label and the + link across cells (Talos) and the row's text never names both items. + Only a heading whose first item is this section's item counts. + """ + if not item or not section_text: + return () + for line in section_text[:_HEADING_SCAN_CHARS].splitlines(): + line = re.sub(r'^[\s*#_>|]+', '', line).rstrip() + if not line or len(line) > _HEADING_MAX_LEN: + continue + combined = TOCAnalyzer.combined_item_numbers(line) + if combined and combined[0] == item.upper(): + return combined + return () + class TOCSectionDetector: """ @@ -122,6 +153,7 @@ def extract_text(section_name=None, **kwargs): # Create Section with TOC confidence section = Section( + covered_items=_covered_items(item, section_text), name=section_name, title=section_info.get('canonical_name', section_name), node=section_node, diff --git a/edgar/documents/utils/toc_analyzer.py b/edgar/documents/utils/toc_analyzer.py index 146155bfc..feb90cd7e 100644 --- a/edgar/documents/utils/toc_analyzer.py +++ b/edgar/documents/utils/toc_analyzer.py @@ -1325,6 +1325,29 @@ def _combined_part_item_label(cls, text: str) -> Optional[Tuple[str, str]]: part, num, letter = match.groups() return f"Part {part.upper()}", f"Item {num}{(letter or '').upper()}" + # "Items 1 and 2. Business and Properties", "Items 1. and 2.", "Items\xa01. and 2.", + # "Items 7. and 7A." — two items a filer files under one heading (GH #710, #1382). + # `\s` matches the non-breaking space these TOCs use after "Items". + _COMBINED_ITEMS = re.compile( + r'items\s+(\d+)([A-Za-z])?\s*\.?\s*(?:and|&)\s*(\d+)([A-Za-z])?(?=\W|$|[A-Z][a-z])', + re.IGNORECASE) + + @classmethod + def combined_item_numbers(cls, text: str) -> Optional[Tuple[str, str]]: + """The two item numbers of a combined "Items N and M" label, e.g. ``('7', '7A')``. + + Returns ``None`` unless the text opens with such a label. A letter glued + to a following title word is not a suffix, as in :meth:`_item_label_from_text`. + """ + match = cls._COMBINED_ITEMS.match((text or '').strip()) + if not match: + return None + first_num, first_letter, second_num, second_letter = match.groups() + if second_letter and text.strip()[match.end():][:1].islower(): + second_letter = None + return (f"{first_num}{(first_letter or '').upper()}", + f"{second_num}{(second_letter or '').upper()}") + @staticmethod def _item_label_from_text(text: str) -> Optional[str]: """Normalize a leading ``Item N`` label, ignoring a title glued onto it. @@ -1348,8 +1371,17 @@ def _item_label_from_text(text: str) -> Optional[str]: body-scan counter already allows for Caterpillar's Item 1D) — and it keeps a genuinely glued suffix working: "Item 1ARisk Factors" -> Item 1A. + A combined label ("Items 1 and 2. Business and Properties") names its + first item: the section is keyed as that item and records the second in + ``Section.covered_items``. Rejecting the plural dropped the whole row, so + Items 1 and 2 had no section at all on Viper, Devon, Freeport and + Cheniere (GH #1382). + Returns ``None`` when the text does not open with an item label. (GH #923) """ + combined = TOCAnalyzer.combined_item_numbers(text) + if combined: + return f"Item {combined[0]}" match = re.match(r'item\s+(\d+)([A-Za-z])?', text, re.IGNORECASE) if not match: return None diff --git a/tests/fixtures/html/fcx/10k/fcx-10-k-2025-02-14.html b/tests/fixtures/html/fcx/10k/fcx-10-k-2025-02-14.html new file mode 100644 index 000000000..775bb0e5c --- /dev/null +++ b/tests/fixtures/html/fcx/10k/fcx-10-k-2025-02-14.html @@ -0,0 +1,8 @@ + + + + + + + +fcx-20241231
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from   to
Commission file number: 001-11307-01
fcx_logoa45.jpg
Freeport-McMoRan Inc.
(Exact name of registrant as specified in its charter)
Delaware74-2480931
(State or other jurisdiction of(I.R.S. Employer Identification No.)
incorporation or organization) 
333 North Central Avenue
PhoenixArizona85004-2189
(Address of principal executive offices)(Zip Code)
(602) 366-8100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.10 per shareFCXThe New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act  ☑ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☑ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   ☑ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☑ Yes ☐ No                         
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.   
Large accelerated filer
☑
Accelerated filer
☐
Non-accelerated filer  
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.             ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.                                      ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.                    ☐    
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).    ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).                               ☐ Yes ☑ No
The aggregate market value of common stock held by non-affiliates of the registrant was $69.5 billion on June 30, 2024.
Common stock issued and outstanding was 1,437,073,006 shares on January 31, 2025.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for its 2025 annual meeting of stockholders are incorporated by reference into Part III of this report.


Freeport-McMoRan Inc.
TABLE OF CONTENTS
  
 Page
 76
  
 
Item 6. Reserved
 
  
 
  
  
  


i
Table of Contents
PART I
Items 1. and 2. Business and Properties.

All of our periodic reports filed with the United States (U.S.) Securities and Exchange Commission (SEC) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available, free of charge, through our website, fcx.com, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports. These reports and amendments are available through our website as soon as reasonably practicable after we electronically file or furnish such material to the SEC. Our website is for information only and the contents of our website or information connected thereto are not incorporated in, or otherwise to be regarded as part of, this Form 10-K.

References to “we,” “us” and “our” refer to Freeport-McMoRan Inc. (FCX) and its consolidated subsidiaries. References to “Notes” refer to the Notes to Consolidated Financial Statements included herein (refer to Item 8.), and references to “MD&A” refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk included herein (refer to Items 7. and 7A.). The following discussions include forward-looking statements that are not guarantees of future performance and actual results may differ materially (refer to Item 1A. “Risk Factors” and “Cautionary Statement” in MD&A for further discussion).

GENERAL

We are a leading international metals company with the objective of being foremost in copper. Headquartered in Phoenix, Arizona, we operate large, long-lived, geographically diverse assets with significant proven and probable mineral reserves of copper, gold and molybdenum. We are one of the world’s largest publicly traded copper producers. Our portfolio of assets includes the Grasberg minerals district in Indonesia, one of the world’s largest copper and gold deposits; and significant operations in North America and South America, including the large-scale Morenci minerals district in Arizona and the Cerro Verde operation in Peru.

Our results for 2024 reflect solid execution of our operating plans and we are committed to enhancing productivity, managing costs and capital and advancing opportunities for long-term profitable growth and value creation. We believe the actions we have taken in recent years to strengthen our balance sheet and maintain flexible organic growth options will allow us to continue to execute our business plans, and reliably and responsibly generate cash flows to pursue value-enhancing organic growth options and return cash to shareholders.

We believe that we have a high-quality portfolio of long-lived copper assets positioned to generate long-term value, and we remain focused on executing our operating and investment plans. Our underground mining operations at the Grasberg minerals district in Indonesia continue to perform well, with copper production increasing in each of the past three years. During 2024, construction of PT Freeport Indonesia’s (PT-FI) new smelter and precious metals refinery (PMR) (collectively, PT-FI’s new downstream processing facilities) in Eastern Java, Indonesia were completed and as part of start-up activities, PT-FI commenced gold production from the PMR in December 2024. In October 2024, during start-up activities of the new smelter, a fire occurred requiring a temporary suspension of smelting operations to complete repairs. PT-FI expects repairs to be completed by mid-2025 and ramp-up to full capacity to be achieved by year-end 2025.

We are progressing initiatives across our North America and South America operations by incorporating new applications, technologies and data analytics to our leaching processes. Incremental copper production from these initiatives totaled 214 million pounds in 2024, compared with a total of 144 million pounds in 2023. We have projects underway to apply recent operational enhancements to our leaching processes on a larger scale and are testing new innovative technology applications that we believe have the potential for significant increases in recoverable metal from leach stockpiles beyond the current run rate.

We believe we benefit from significant copper reserves and resources with embedded growth options, an experienced team and exposure to markets with a favorable fundamental outlook.

For the year 2024, the London Metal Exchange (LME) copper settlement prices averaged $4.15 per pound (ranging from a low of $3.67 per pound to a high of $4.92 per pound) and closed at $3.95 per pound on December 31, 2024. We believe fundamentals for copper are favorable with growing demand supported by copper’s critical role in the global transition to renewable power, electric vehicles and other carbon-reduction initiatives, continued urbanization in developing countries, data centers and artificial intelligence developments and growing connectivity globally.
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Following are our ownership interests at December 31, 2024, in operating mines through our consolidated subsidiaries, Freeport Minerals Corporation (FMC) and PT-FI:
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a.Refer to Note 2 for discussion of our conclusion to consolidate PT-FI.
b.FMC has a 72% undivided interest in Morenci via an unincorporated joint venture. Refer to Note 2 for further discussion.
c.FMC’s interest in Cerro Verde is 55.08%, and prior to September 2024 was 53.56%.

Following is the allocation of our estimated consolidated recoverable proven and probable mineral reserves at December 31, 2024, by geographic location (refer to “Operations” and “Mineral Reserves” for further discussion):
CopperGoldMolybdenum
North America43 %3 %79 %
a
South America29 — 21 
Indonesia28 97 — 
100 %100 %100 %
a.Our North America copper mines contain 61% of our estimated consolidated recoverable proven and probable molybdenum reserves, and our Henderson and Climax molybdenum mines contain 18%.

In North America, we manage seven copper operations – Morenci, Bagdad, Safford (including Lone Star), Sierrita and Miami in Arizona, and Chino and Tyrone in New Mexico, and two molybdenum mines – Henderson and Climax in Colorado. We also operate a copper smelter in Miami, Arizona. In addition to copper, certain of our North America copper mines also produce molybdenum concentrate, gold and silver.

In South America, we manage two copper operations – Cerro Verde in Peru and El Abra in Chile. In addition to copper, the Cerro Verde mine also produces molybdenum concentrate and silver.

In Indonesia, PT-FI operates in the Grasberg minerals district. In addition to copper, the Grasberg minerals district also produces gold and silver. Upon completion and full ramp-up of PT-FI’s new downstream processing facilities, PT-FI will be a fully integrated producer of refined copper and gold.
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Following is the allocation of our consolidated copper, gold and molybdenum production for the year 2024 by geographic location (refer to “Operations” and MD&A for further information):
CopperGoldMolybdenum
North America29 %1 %75 %
a
South America28 — 25 
Indonesia43 99 — 
100 %100 %100 %
a.Our North America copper mines produced 38% of our consolidated molybdenum production, and our Henderson and Climax molybdenum mines produced 37%.

Copper production from three of our mines (the Morenci mine in North America, the Cerro Verde mine in Peru and the Grasberg minerals district in Indonesia) together totaled 77% of our consolidated copper production in 2024.

The geographic locations of our operating mines are shown on the world map below.
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COPPER, GOLD AND MOLYBDENUM

The following provides a summary of our primary natural resources – copper, gold and molybdenum. Refer to MD&A for further discussion of historical and current market prices of these commodities and Item 1A. “Risk Factors” for discussion of factors that can cause price fluctuations.

Copper
Copper is an internationally traded commodity, and its prices are determined by the major metals exchanges – the LME, Commodity Exchange Inc. (COMEX) and Shanghai Futures Exchange. Prices on these exchanges generally reflect the worldwide balance of copper supply and demand, and can be volatile and cyclical.

In general, demand for copper reflects the rate of underlying world economic growth, particularly in industrial production and construction. According to a 2024 report from Wood Mackenzie, a widely followed independent metals market consultant, copper’s end-use markets (and their estimated shares of total consumption) are electrical applications (29%), construction (25%), consumer products (21%), transportation (14%) and industrial machinery (11%). We believe copper will continue to be essential in these basic uses as well as contribute significantly to new technologies for clean energy and advancement in communications, including the global transition to renewable
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power, electric vehicles and other carbon-reduction initiatives, continued urbanization in developing countries, data centers and artificial intelligence developments and growing connectivity globally. Examples of areas we believe will require additional copper in the future include: (i) high efficiency motors, which consume up to 75% more copper than a standard motor; (ii) electric vehicles, which consume up to four times the amount of copper in terms of weight compared to vehicles of similar size with an internal combustion engine, and require copper-intensive charging station infrastructure to refuel; and (iii) renewable energy such as wind and solar, which consume four to five times the amount of copper compared to traditional fossil fuel generated power.

Gold
Gold is used for jewelry, coinage and bullion as well as various industrial and electronic applications. Gold can be readily sold on numerous markets throughout the world. Benchmark prices are generally based on London Bullion Market Association (London) quotations.

Molybdenum
Molybdenum is a key alloying element in steel and the raw material for several chemical-grade products used in catalysts, lubrication, smoke suppression, corrosion inhibition and pigmentation. Molybdenum-based chemicals are used to produce high-purity molybdenum metal used in electronics such as flat-panel displays and in super alloys used in aerospace. Like copper, demand for molybdenum is positively impacted by new technologies for clean energy. Reference prices for molybdenum are available in several publications, but generally based on Platts Metals Daily.

PRODUCTS AND SALES

Our consolidated revenues for 2024 primarily included sales of copper (74%), gold (17%) and molybdenum (7%). For the three years ended December 31, 2024, the only customers that accounted for 10% or more of our consolidated revenues were Mitsubishi Materials Corporation (MMC), PT-FI’s joint venture partner in PT Smelting (PT-FI’s 66%-owned copper smelter and refinery), in 2024 and PT Smelting in 2022. Beginning January 1, 2023, PT-FI’s commercial arrangement with PT Smelting changed to a tolling arrangement so there were no further sales from PT-FI to PT Smelting (refer to Note 2 for further discussion) during 2023 and 2024. Refer to Note 14 for a summary of our consolidated revenues by product and geographic area, and revenues and operating income (loss) by business segment.

Copper Products
We are one of the world’s leading producers of copper concentrate, cathode and continuous cast copper rod. During 2024, 45% of our mined copper was sold in concentrate, 34% as cathode and 21% as rod. The copper ore from our mines is generally processed either by smelting and refining or by solution extraction and electrowinning (SX/EW) as described below.

Copper Concentrate. We produce copper concentrate at six of our mines in which mined ore is crushed and treated to produce a copper concentrate with copper content of approximately 20% to 30%. In North America, copper concentrate is produced at the Morenci, Bagdad, Sierrita and Chino mines, and a significant portion is shipped to our Miami smelter in Arizona for further processing. Copper concentrate is also produced at the Cerro Verde mine in Peru and the Grasberg minerals district in Indonesia. Historically, copper concentrate produced in the Grasberg minerals district has been shipped to PT Smelting in Indonesia, Atlantic Copper in Spain and third-party smelters outside of Indonesia. Once PT-FI’s new smelter is fully operational, all of Grasberg’s copper concentrate is expected to be processed within Indonesia.

Copper Cathode. We produce copper cathode at our electrolytic refinery located in El Paso, Texas, and at nine of our mines. 

SX/EW cathode is produced from the Morenci, Bagdad, Safford, Sierrita, Miami, Chino and Tyrone mines in North America, and from the Cerro Verde and El Abra mines in South America. For ore subject to the SX/EW process, the ore is placed on stockpiles and copper is extracted from the ore by dissolving it with a weak sulfuric acid solution. The copper content of the solution is increased in two additional SX stages, and then the copper-bearing solution undergoes an EW process to produce cathode that is, on average, 99.99% copper. Our copper cathode is used as the raw material input for copper rod, brass mill products and for other uses.

Copper cathode is also produced at Atlantic Copper (our wholly owned copper smelting and refining unit in Spain) and PT Smelting. Copper concentrate is smelted (i.e., subjected to extreme heat) to produce copper anode, which
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weighs between 700 and 900 pounds and has an average copper content of 99.5%. We operate a copper smelter in Miami, Arizona that produces copper anode. The anode is further treated by electrolytic refining to produce copper cathode, which weighs between 100 and 350 pounds and has an average copper content of 99.99%. Refer to “Smelting Facilities and Other Mining Properties” for further discussion of PT-FI’s new downstream processing facilities, Atlantic Copper, PT Smelting and the Miami smelter.

Continuous Cast Copper Rod. We manufacture continuous cast copper rod at our facilities in El Paso, Texas and Miami, Arizona, primarily using copper cathode produced at our North America copper mines.

Copper Sales
North America. The majority of the copper produced at our North America copper mines and refined in our El Paso, Texas refinery is consumed at our rod plants to produce copper rod, which is then sold to wire and cable manufacturers. The remainder of our North America copper production is sold in the form of copper cathode or copper concentrate under U.S. dollar-denominated annual contracts. Generally, copper cathode is sold to rod, brass or tube fabricators. Cathode and rod contract prices are generally based on the prevailing COMEX monthly average settlement price for the month of shipment and include a premium.

South America. Production from our South America operations is sold as copper concentrate or copper cathode under U.S. dollar-denominated, annual and multi-year contracts. During 2024, our South America operations sold 74% of their copper production in concentrate and 26% as cathode.

Substantially all of our South America copper concentrate and cathode sales contracts provide final copper pricing in a specified future month (generally one to four months from the shipment date) primarily based on quoted LME monthly average settlement copper prices. Revenues from our South America concentrate sales are recorded net of royalties and treatment charges (i.e., fees paid to smelters that are generally negotiated annually). In addition, because a portion of the metals contained in copper concentrate is unrecoverable from the smelting process, revenues from our South America concentrate sales are also recorded net of allowances for unrecoverable metals, which are a negotiated term of the contracts and vary by customer.

Indonesia. PT-FI has historically sold its production in the form of copper concentrate, which contains significant quantities of gold and silver, primarily under U.S. dollar-denominated, long-term contracts. PT-FI sells a small amount of copper concentrate in the spot market. Following the full ramp-up of PT-FI’s new downstream processing facilities, PT-FI’s mining and smelting operations will be fully integrated and copper sales will be in the form of copper cathodes.

Beginning in 2023, PT-FI’s commercial arrangement with PT Smelting changed to a tolling arrangement so there were no further sales from PT-FI to PT Smelting during 2023 and 2024. Under this arrangement, PT-FI pays PT Smelting a tolling fee to smelt and refine its concentrate and PT-FI retains title to all products for sale to third parties. PT-FI’s sale of copper cathodes under the tolling arrangement are priced in the month of shipment and are not subject to provisional pricing.

During 2024, PT-FI sold 56% of its copper production in concentrate and 44% as cathode.

Substantially all of PT-FI’s copper concentrate sales contracts provide final pricing in a specified future month (generally one to four months from the shipment date) primarily based on quoted LME monthly average settlement copper prices. Revenues from PT-FI’s concentrate sales are recorded net of royalties, export duties, treatment charges and allowances for unrecoverable metals. Revenues from PT-FI’s cathode sales are recorded net of royalties.

Refer to Item 1A. “Risk Factors,” “Operations – Indonesia” in MD&A and Notes 10 and 11 for a discussion of Indonesia regulatory matters, including those related to export licenses, export duties and export proceeds.


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Gold Products and Sales
We produce gold almost exclusively from our mines in the Grasberg minerals district. The gold we produce is primarily sold as a component of our copper concentrate or in anode slimes, which are a product of the smelting and refining process. Gold generally is priced at the average London price for a specified month near the month of shipment. Revenues from gold sold as a component of our copper concentrate are recorded net of treatment charges, royalties, export duties and allowances for unrecoverable metals. Revenues from gold sold in anode slimes are recorded net of royalties and refining charges. As part of start-up activities, PT-FI commenced gold production from its new PMR in December 2024. We began selling gold bars produced by the PMR in February 2025 and the related revenues are recorded net of royalties.

Molybdenum Products and Sales
According to Wood Mackenzie, we are the world’s largest producer of molybdenum and molybdenum-based chemicals. In addition to production from the Henderson and Climax molybdenum mines, we produce molybdenum concentrate at certain of our North America copper mines and our Cerro Verde copper mine in Peru. The majority of our molybdenum concentrate is processed in our own conversion facilities. Our molybdenum sales are primarily priced based on the average published Platts Metals Daily prices for the month prior to the month of shipment.

GOVERNMENTAL REGULATIONS

Our operations are subject to a broad range of laws and regulations imposed by governments and regulatory bodies, both in the U.S. and internationally. These laws and regulations touch all aspects of our operations, the most significant of which include how we extract, process and explore for minerals and how we conduct our business, including laws and regulations governing matters such as mining rights, environmental and reclamation matters, climate change, occupational health and safety, and human rights. Compliance with these laws and regulations requires expenditures for the implementation, operation and maintenance of systems and programs, but has not had and is not expected to have a material adverse effect on our expenditures, results of operations or competitive position. We continuously monitor and strive to maintain compliance with changes in laws and regulations that impact our business.

Mining Rights
We conduct our mining and exploration activities pursuant to concessions granted by, or under contracts with, the host government in the countries where we operate. These countries include, among others, the U.S., Peru, Chile and Indonesia. Mining rights include our license to operate and involve our payment of applicable taxes and royalties to the host governments. The concessions and contracts are subject to the political risks associated with the host countries. For information about mining rights, governmental agreements, licenses to operate, and tax regulations and related matters refer to “Operations” below, Item 1A. “Risk Factors” and Notes 2, 9, 10 and 11.

Environmental Matters
Our operations are subject to extensive and complex environmental laws and regulations governing the generation, storage, treatment, transportation and disposal of hazardous substances; solid waste disposal; air emissions; wastewater discharges; remediation, restoration and reclamation of environmental contamination, including mine closures and reclamation; protection of endangered and threatened species and designation of critical habitats; and other related matters. In addition, we must obtain regulatory permits and approvals to start, continue and expand operations. As a mining company, compliance with environmental, health and safety laws and regulations is an integral and costly part of our business. We conduct our operations in a manner that aims to protect public health and the environment. We believe our operations follow applicable laws and regulations in all material respects, and we have internal company policies that in some instances go beyond compliance with such laws and regulations.

At December 31, 2024, we had $2.0 billion recorded in our consolidated balance sheet for environmental obligations and $3.7 billion recorded for asset retirement obligations. We incurred environmental capital expenditures and other environmental costs (including our joint venture partners’ shares) to comply with applicable environmental laws and regulations that affect our operations totaling $0.6 billion in 2024, $0.5 billion in 2023 and $0.4 billion in 2022, and we expect to incur approximately $0.6 billion in 2025. The timing and amounts of estimated payments could change as a result of changes in regulatory requirements, changes in scope and costs of reclamation activities, the settlement of environmental matters and the rate at which actual spending occurs on continuing matters.

For information about environmental laws and regulations at our global operations, including legal proceedings and related costs, and reclamation matters, see below as well as Item 1A. “Risk Factors,” Item 3 “Legal Proceedings” and Notes 1, 10 and 11.
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United States. There are a number of federal and state environmental laws and regulations that apply to our properties and may affect our operations. Laws such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA) and similar state laws may expose us to joint and several liability for environmental damages caused by our operations, or by previous owners or operators of properties we acquired or are currently operating or at sites where we previously sent materials for processing, recycling or disposal. Other federal and comparable state environmental laws have affected, or could in the future affect, us including, but not limited to, the Resource Conservation and Recovery Act, the Clean Air Act and the National Environmental Policy Act. We have substantial obligations for environmental remediation on mining properties previously owned or operated by FMC and certain of its affiliates.

Our operations are subject to state regulations governing mine closures and reclamation. Closure plans are required to be updated every six years in Arizona and every five years in New Mexico and Colorado. We are also required by U.S. federal and state laws and regulations to provide financial assurance sufficient to allow a third party to implement approved closure and reclamation plans for our mining properties if we are unable to do so. Most of our financial assurance obligations are imposed by state laws that vary significantly by jurisdiction, depending on how each state regulates land use and groundwater quality. The U.S. Environmental Protection Agency (EPA) and state agencies may also require financial assurance for investigation and remediation actions that are required under settlements of enforcement actions under CERCLA or similar state laws.

Regulations have been, and may in the future be, considered at various governmental levels to increase financial responsibility requirements both for mine closure and reclamation. Further, there has been consideration of reforms to federal mining laws, including enhancement of laws, regulations and policies governing financial assurance, which if ever enacted, may be applicable to us.

Our U.S. mining operations are also subject to regulations under the Endangered Species Act (ESA) that are intended to protect species listed by the Department of the Interior’s Fish & Wildlife Service (FWS) as endangered or threatened, along with critical habitat designated by FWS for these listed species. The ESA may affect the ability of landowners, including us, to obtain federal permits or authorizations needed for expansion of our operations, and may also affect our ability to obtain, retain or deliver water to some operations.

New or revised environmental regulatory requirements are frequently proposed, many of which result in substantially increased costs for our business, including those regarding financial assurance discussed above and in Item 1A. “Risk Factors.” For example, in May 2024, EPA amended its rule establishing standards for hazardous air pollutant emissions from primary copper smelters. This final rule will impact our Miami, Arizona smelter operations, which process a significant portion of the copper concentrate produced by our North America copper mines. We are evaluating processes and equipment modifications and the costs involved, which could be significant in connection with the revised rule requirements. Our appeal of EPA’s final rule to the Court of Appeals for the District of Columbia Circuit is suspended pending resolution of several petitions for reconsideration to the EPA filed by us and other parties.

EPA and state agencies continue to consider regulations for man-made organic compounds that could be present in soil, groundwater and surface water at our existing and former operations. These regulations may include drinking water standards, hazardous waste requirements, and hazardous substance designations for Perfluorooctanesulfonic and Perfluorooctanoic acids. In January 2024, EPA announced through guidance that, effective immediately, it lowered the recommended screening levels for investigation and cleanup of lead in residential soils, and in January 2025, EPA published its final toxicological assessment for inorganic arsenic, which may be used to calculate cleanup levels at state and federal remediation sites and may lead to regulatory guidance, rulemaking and other regulatory activities. We are working with state agencies to understand possible ramifications of this guidance to our projects. This EPA guidance and future changes to EPA’s lead and arsenic cleanup levels could result in increases to our environmental reserves for ongoing residential property cleanup projects near former smelter sites.

In 2023, EPA and the U.S. Army Corps of Engineers issued a final rule to amend the final revised definition of the “waters of the United States.” Although future court decisions may further affect the scope of the final rule and legal challenges have already been successful, we may need federal authorization under the Clean Water Act to expand some of our operations.


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Peru. The General Environmental Law (Law No. 28611) establishes the main environmental guidelines and principles applicable in Peru. Pursuant to the General Environmental Law, Ministry of Energy and Mines (MINEM) issued national environmental regulations, which have gradually replaced prior guidelines governing governmental agencies’ environmental competencies. The Environmental Evaluation and Oversight Agency has the authority to inspect mining operations and fine companies that fail to comply with prescribed environmental regulations and their approved environmental assessments.

Cerro Verde is subject to regulation under the Mine Closure Law administered by MINEM. Under the closure regulations, mines must submit a closure plan that includes the reclamation methods, closure cost estimates, methods of control and verification, closure and post-closure plans, and financial assurance. In compliance with the requirement for five-year updates, Cerro Verde submitted its updated closure plan and cost estimates and received approval from MINEM in December 2023.

The Cerro Verde mine has developed and continues to implement detailed, comprehensive mine waste and tailings management programs to meet the applicable Peru waste regulations and our environmental management practices. These programs incorporate commitments included in the Environmental and Social Impact Studies and the engineer of record designs for the specific cases of tailings storage facilities and certain leach pad stockpiles. For any future projects, including for existing facilities, Cerro Verde also may be required by MINEM or the National Environmental Certification Service for Sustainable Investments to incur additional costs to comply with the requirements of new regulations that provide for the adequacy of the transportation and final disposal of tailings.

Chile. El Abra is subject to regulation under the Mine Closure Law administered by the Chile Mining and Geology Agency. In compliance with the requirement for five-year updates, El Abra is working to submit an updated plan with closure cost estimates in the second half of 2025.

Indonesia. PT-FI holds multiple permits from national, provincial, and regency regulatory agencies, including groundwater use permits, effluent and air discharge permits, solid and hazardous waste storage and management permits and protection of forest borrow-to-use permits. Where permits have specific terms, renewal applications are made to the relevant regulatory authority as required, prior to the end of the permit term.

In December 2018, Indonesia’s Ministry of Environment and Forestry (MOEF) issued a revised environmental permit to PT-FI to address certain operational activities that it alleged were inconsistent with earlier studies. PT-FI and the MOEF also established a new framework known as the Tailings Management Roadmap for continuous improvement in environmental practices at PT-FI’s operations, including initiatives to potentially increase tailings retention and to evaluate large scale beneficial uses of tailings within Indonesia. The third-party expert nominated by MOEF to perform the framework evaluation submitted its report to the MOEF in June 2021. In 2024, PT-FI continued to work with MOEF on the Tailings Management Roadmap objectives, including further reduction of non-tailings sediment entering the tailings management area, construction of bamboo and geotube structures in the estuary portion of the tailings management area to increase sedimentation and reduce erosion, as well as continue pursuing additional beneficial uses of tailings in infrastructure and other projects. In October 2024, MOEF approved the next phase of the Tailings Management Roadmap, which extends from 2025 to 2030 and continues activities from the initial period with additional programs and studies for continuous improvement in tailings management.

In 2020, PT-FI initiated a new environmental impact analysis (called an Analisis Mengenai Dampak Lingkungan or AMDAL) in preparation for the proposed activities associated with the transition from Grasberg surface mine to underground operations, and PT-FI completed the approval requirements of the AMDAL covering all support activities for the underground transition in 2023. In December 2023, PT-FI received technical approval for its tailings management activities. In 2024, the MOEF approved an addendum to the AMDAL that covers activities associated with the conversion of PT-FI’s power plant from coal-fired to liquefied natural gas (LNG). Permitting related to the conversion to LNG continues to progress.

A detailed mine closure plan and five-year reclamation plan have been approved by Indonesia regulators as required by Indonesia law. The mine closure plan is reviewed annually and required reclamation bonds are in place. In 2019, PT-FI completed and received approval on an updated mine closure plan to reflect Grasberg minerals district production operations until 2041 and PT-FI will be required to fund the next mine closure guarantee in 2025. PT-FI’s most recent five-year reclamation plan covering 2022 through 2026 was approved in early 2022. In the future, additional approval will be required for the diversion of the Aghawagon/Otomona River out of the tailings management area at the end of the mine life.

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Climate
In many of the jurisdictions in which we or our customers operate, governmental bodies are increasingly enacting legislation and regulations in response to the potential impacts of climate change, including:
•As a result of the 2015 Paris Agreement, a number of governments, including Peru, Indonesia and Chile, have pledged “Nationally Determined Contributions” to control and reduce greenhouse gas emissions (GHG).
•Several states in the U.S., including Colorado and New Mexico, have advanced goals reducing or eliminating fossil fuel-based energy production and use.
•Carbon tax legislation also has been adopted in jurisdictions where we operate, including Indonesia, Chile and the European Union (EU). Starting in 2025, PT-FI's coal-fired power plant will be subject to a carbon emissions trade system based on reported emissions submitted to the regulators in early 2026. Refer to “Operations – Indonesia” below for discussion of PT-FI’s plans to transition its existing energy source from coal to natural gas.

Regulations that affect us also may include mandated corporate climate-related reporting, including:
•The SEC’s new climate-related disclosure rules, which are being challenged in federal courts.
•The EU’s Corporate Sustainability Reporting Directive, which requires in scope entities to provide detailed reporting on climate change and other sustainability topics.
•The EU’s Corporate Sustainability Due Diligence Directive which will require in scope entities to identify, assess and address various social and environmental topics.
•California’s Climate Corporate Data Accountability Act and Climate-Related Financial Risk Act, which are being challenged in federal courts, and Voluntary Carbon Market Disclosures Act, which were enacted in 2023. Legislation similar to California’s is also under consideration in other states.

While it is not yet possible to reasonably estimate the nature, extent, timing and cost or other impacts of any future carbon pricing mechanisms, mandatory disclosures, other climate change regulatory programs or future legislative action that may be enacted, we anticipate that we will dedicate more resources and incur more costs to comply and remediate in response to legislative or regulatory changes.

For information about the risks posed by the potential impacts of climate change and related regulations, refer to Item 1A. “Risk Factors.”

Health and Safety
Our highest priority is the health, safety and well-being of our employees and contractors. We also work to promote our safety-first values with our suppliers and in the communities where we operate. We believe health and safety considerations are integral to, and fundamental for, all other functions in our organization, and we understand the health and safety of our workforce is critical to our operational efficiency and long-term success. We are subject to extensive U.S. and international regulation of worker health and safety, including the requirements of the U.S. Occupational Safety and Health Act and similar laws of other jurisdictions. For example, in the U.S., the operation of our mines is subject to regulation by the U.S. Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act). MSHA inspects our mines on a regular basis and issues citations and orders when it believes a violation has occurred under the Mine Act. In 2024, MSHA enacted the Safety Program for Surface Mobile Equipment regulation and finalized a new regulation, which reduces permissible exposure limits of respirable crystalline silica effective April 2026. Our compliance with these or any other new health and safety regulations could increase our mining costs. If we were found to be in violation of these regulations we could face penalties or restrictions that may materially and adversely affect our operations.

Additionally, in the U.S., various state agencies have concurrent jurisdiction arising under state law that regulate worker health and safety in both our industrial facilities and mines. If regulatory inspections result in an alleged violation, we may be subject to fines and penalties and, in instances of alleged significant violations, our mining operations or industrial facilities could be subject to temporary or extended closures. Refer to Exhibit 95.1 to this Form 10-K for additional information regarding certain orders and citations issued by MSHA for our operations during the year ended December 31, 2024. For information about health and safety, refer to “Human Capital” below and Item 4. “Mine Safety Disclosures.”


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Human Rights
We are dedicated to the recognition, respect and promotion of human rights wherever we do business. We are committed to respecting the rights of all people, including our employees, business partners, community members and others who potentially may be impacted by our business activities. We take this obligation seriously in all aspects of our business, and we expect the same of our business partners.

For information about human rights, refer to “Community and Human Rights” below.

COMPETITION

The top 10 producers of copper comprise approximately 40% of total worldwide mined copper production. Based on Wood Mackenzie’s December 2024 estimates, we ranked third among those producers for the year 2024, with approximately 6% of estimated total worldwide mined copper production based on net equity ownership. We believe our competitive position is based on the size, quality and grade of our ore bodies and our ability to manage costs compared with other producers. We have a diverse portfolio of mining operations with varying ore grades and cost structures. Our costs are driven by the location, grade and nature of our ore bodies, and the level of input costs, including energy, labor and equipment. The metals markets are cyclical, and we believe our ability to maintain our competitive position over the long term is based on our ability to acquire and develop quality deposits (including the expansion of deposits at our existing mine sites); recruit, retain, develop and advance a skilled workforce; and to manage our costs.

OPERATIONS

Responsible Production
We demonstrate our responsible production performance through the Copper Mark, a comprehensive assurance framework developed specifically for the copper industry, and recently extended to other metals including molybdenum. To achieve the Copper Mark, each site is required to complete an independent external assurance process to assess conformance with various environmental, social and governance criteria. Awarded sites must be revalidated every three years. We have achieved, and are committed to maintaining, the Copper Mark and/or Molybdenum Mark, as applicable, at all of our operating sites globally.

We are also a founding member of the International Council on Mining & Metals (ICMM), an organization dedicated to a safe, fair and sustainable mining and metals industry, aiming continuously to strengthen performance across the global mining and metals industry. As a member company, we are required to implement the 10 Mining Principles which define good environmental, social and governance practices, and associated position statements, while also meeting 39 performance expectations.

Tailings Management
We dedicate substantial financial resources and internal and external technical resources to pursue the safe management of our tailings facilities and to reduce or eliminate the number of and potential consequences of credible failure modes. Our tailings management and stewardship program, which involves qualified external engineers of record and periodic oversight by an independent tailings review board and our tailings stewardship team, conform with the tailings governance framework on preventing catastrophic failure of tailings storage facilities adopted by the ICMM. Further, our tailings management policy outlines our continued commitment to managing our tailings responsibly and effectively across our sites globally. As an ICMM member and in accordance with our commitment in our tailings management policy, we also have implemented the Global Industry Standard on Tailings Management (the Tailings Standard) for all tailings storage facilities with “Extreme” or “Very High” potential consequences based on “credible failure modes” and are committed to implementing the Tailings Standard by August 2025 for all other tailing storage facilities that have not been deemed “Safely Closed” (each as defined in the Tailings Standard). We believe we have the financial capacity to meet current estimated lifecycle costs, including estimated closure, post-closure and reclamation obligations associated with our tailings storage facilities. We continue to enhance our existing practices to strengthen the design, operation and closure of tailings storage facilities in an effort to reduce the risk of severe or catastrophic failure of those facilities.

Refer to Item 1A. “Risk Factors” for further discussion of the risks associated with our tailings management.


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Overview of Mines
Following are maps and descriptions of our copper and molybdenum mining operations in North America, South America and Indonesia. We consider our material mines, as defined under the disclosure requirements of Subpart 1300 of SEC Regulation S-K, to be the Morenci mine in the U.S., the Cerro Verde mine in Peru and the Grasberg minerals district in Indonesia. Refer to Exhibits 96.1, 96.2 and 96.3 for the Technical Report Summaries that have been prepared for our material mines.

North America
In the U.S., most of the land occupied by our copper and molybdenum mines, concentrators, SX/EW facilities, smelter, refinery, rod mills, molybdenum roasters and processing facilities is owned by us or is located on unpatented mining claims owned by us. Certain portions of our Bagdad, Sierrita, Miami, Chino, Tyrone, Henderson and Climax operations are located on government-owned land and are operated under a Mine Plan of Operations or other use permit. We hold various federal and state permits or leases on government land for purposes incidental to mine operations.

Morenci
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We own a 72% undivided interest in Morenci, with the remaining 28% owned by Sumitomo Metal Mining Arizona, Inc. (15%) and SMM Morenci, Inc. (13%). Each partner takes in kind its share of Morenci’s production.

Morenci is an open-pit copper and molybdenum mining complex that has been in continuous operation since 1939 and previously was mined through underground workings. In the 1880s, Phelps Dodge & Company (Phelps Dodge) first invested in the area, and through acquisition, consolidated all mining operations in the area by the 1920s. Phelps Dodge was acquired by FCX in 2007. Morenci is located in Greenlee County, Arizona, approximately 50 miles northeast of Safford on U.S. Highway 191. The property is located at latitude 33.07 degrees north and longitude 109.35 degrees west using the World Geodetic System (WGS) 84 coordinate system. The site is accessible by a paved highway and a railway spur.

The Morenci mine is a porphyry copper deposit that has oxide, secondary sulfide and primary sulfide mineralization. The predominant oxide copper mineral is chrysocolla. Chalcocite is the most important secondary copper sulfide mineral, with chalcopyrite as the dominant primary copper sulfide.

The Morenci operation consists of two concentrators with a milling design capacity of 132,000 metric tons of ore per day, which produce copper and molybdenum concentrate; a 72,500 metric ton-per-day, crushed-ore leach pad and stacking system; a low-grade run-of-mine (ROM) leaching system; four SX plants; and three EW tank houses that produce copper cathode. Total EW tank house capacity is approximately 900 million pounds of copper per year. Morenci’s available mining fleet consists of one hundred and forty-one 235-metric-ton haul trucks loaded by 13 electric shovels with bucket sizes ranging from 47 to 59 cubic meters. Morenci’s mining fleet is capable of moving an average of 785,000 metric tons of material per day. Our share of Morenci’s net property, plant, equipment (PP&E) and mine development costs at December 31, 2024, totaled $2.2 billion.

Morenci’s production, including our joint venture partners’ share, totaled 0.7 billion pounds of copper and 3 million pounds of molybdenum in 2024, 0.8 billion pounds of copper and 3 million pounds of molybdenum in 2023, and 0.9 billion pounds of copper and 4 million pounds of molybdenum in 2022.

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Morenci is located in a desert environment with rainfall averaging 13 inches per year. The highest bench elevation is 1,900 meters above sea level and the ultimate pit bottom is expected to have an elevation of 760 meters above sea level. The Morenci operation encompasses approximately 61,700 acres, comprising 51,300 acres of fee lands and 10,400 acres of unpatented mining claims held on public mineral estate and numerous state or federal permits, easements and rights-of-way.

The Morenci operation’s electrical power is supplied by our wholly owned subsidiary, The Morenci Water & Electric Company (MW&E). MW&E sources its generation services through our wholly owned subsidiary, Freeport-McMoRan Copper and Gold Energy Services LLC, through capacity rights at the Luna Energy Facility in Deming, New Mexico, and other power purchase agreements. Although we believe the Morenci operation has sufficient water sources to support current operations, we are a party to litigation that may impact our water right claims or rights to continued use of currently available water supplies, which could adversely affect our water supply for the Morenci operation. Refer to “Governmental Regulations” above, Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” for further discussion.

Bagdad
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Our wholly owned Bagdad mine is an open-pit copper and molybdenum mining complex that has been in continuous operation since 1945 and prior mining was conducted through underground workings. Bagdad is located in Yavapai County in west-central Arizona, approximately 60 miles west of Prescott and 100 miles northwest of Phoenix. The property can be reached by U.S. Highway 93 to State Route 97 or Arizona Highway 96, which ends at the town of Bagdad. The closest railroad is at Hillside, Arizona, 24 miles southeast on Arizona Highway 96.

The Bagdad mine is a porphyry copper deposit containing both sulfide and oxide mineralization. Chalcopyrite and molybdenite are the dominant primary sulfides and are the primary economic minerals in the mine. Chalcocite is the most common secondary copper sulfide mineral, and the predominant oxide copper minerals are chrysocolla, malachite and azurite.

The Bagdad operation consists of a concentrator with a milling design capacity of 77,100 metric tons of ore per day that produces copper and molybdenum concentrate, a SX/EW plant that can produce approximately 9 million pounds per year of copper cathode from solution generated by low-grade stockpile leaching, and a pressure-leach plant to process molybdenum concentrate. The available mining fleet consists of thirty-eight 235-metric-ton haul trucks loaded by 6 electric shovels and 2 loaders with bucket sizes ranging from 30 to 48 cubic meters, which are capable of moving an average of 236,000 metric tons of material per day. In 2023, we announced a project to convert Bagdad’s fleet of haul trucks to become fully autonomous. The testing of the autonomous fleet is expected to begin in second-quarter 2025 with anticipated project completion by year-end 2025. Bagdad’s net PP&E and mine development costs at December 31, 2024, totaled $1.0 billion.

Bagdad’s production totaled 146 million pounds of copper and 13 million pounds of molybdenum in 2024, 146 million pounds of copper and 10 million pounds of molybdenum in 2023, and 165 million pounds of copper and 9 million pounds of molybdenum in 2022.

We have a potential expansion project to more than double the concentrator capacity of the Bagdad operation in northwest Arizona. Bagdad’s reserve life currently exceeds 80 years and supports an expanded operation. In late 2023, we completed technical and economic studies, which indicate the opportunity to construct new concentrating facilities to increase copper production by 200 to 250 million pounds per year at estimated incremental project
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capital costs of approximately $3.5 billion. Expanded operations would provide improved efficiency and reduce unit net cash costs through economies of scale. Project economics indicate that the expansion would require an incentive copper price in the range of $3.50 to $4.00 per pound and approximately three to four years to complete. The decision of whether to proceed and timing of the potential expansion will take into account overall copper market conditions, availability of labor and other factors, including pending conversion of the existing haul truck fleet to autonomous to support long-range plans. In parallel, we are enhancing local infrastructure and advancing activities for expanded tailings infrastructure projects required under long-range plans in order to advance the potential construction timeline. Refer to Item 1A. “Risk Factors” for further discussion.

Bagdad is located in a desert environment with rainfall averaging 15 inches per year. The highest bench elevation is 1,250 meters above sea level and the ultimate pit bottom is expected to be 120 meters above sea level. The Bagdad operation encompasses approximately 53,300 acres, comprising 40,000 acres of fee lands and 13,300 acres of unpatented mining claims held on public mineral estate and numerous state or federal permits, easements and rights-of-ways.

Bagdad receives electrical power from Arizona Public Service Company. We believe the Bagdad operation has sufficient water sources to support current operations.

Safford, including Lone Star
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Our wholly owned Safford mine is an open-pit copper mining complex that has been in operation since 2007. Safford is located in Graham County, Arizona, 8 miles north of the town of Safford and 170 miles east of Phoenix. The site is accessible by a paved county road off U.S. Highway 70.

The Safford mine includes three copper deposits that have oxide mineralization overlaying primary copper sulfide mineralization. The predominant oxide copper minerals are chrysocolla and copper-bearing iron oxides with the predominant copper sulfide material being chalcopyrite. The only Safford deposit currently being mined is Lone Star.

We have commenced pre-feasibility studies in the Lone Star district of Safford to define a potential significant expansion opportunity. Positive drilling conducted in recent years indicates a large, mineralized district with opportunities to pursue a further expansion project. We are expecting to complete these studies in 2026. The decision of whether to proceed and timing of the potential expansion will take into account results of technical and economic studies, overall copper market conditions and other factors.

Safford is a mine-for-leach operation that produces copper cathode. The operation feeds a crushing facility with a design capacity of 103,500 metric tons of ore per day. The crushed ore is delivered to a leach pad by a series of overland and portable conveyors. Leach solutions feed a SX/EW facility with a capacity of 320 million pounds of copper per year. A sulfur burner plant is also in operation at Safford, providing a cost-effective source of sulfuric acid used in SX/EW operations. The available mining fleet consists of fifty-nine 235-metric-ton haul trucks loaded by 7 electric shovels with bucket sizes ranging from 34 to 47 cubic meters, which are capable of moving an average of 408,000 metric tons of material per day. Safford’s net PP&E and mine development costs at December 31, 2024, totaled $1.7 billion.

Safford’s copper production totaled 249 million pounds in 2024, 245 million pounds in 2023 and 285 million pounds in 2022.

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Safford is located in a desert environment with rainfall averaging 10 inches per year. The highest bench elevation is 1,783 meters above sea level and the ultimate pit bottom is expected to have an elevation of 716 meters above sea level. The Safford operation encompasses approximately 78,600 acres, comprising 38,000 acres of fee lands and 40,600 acres of unpatented claims held on public mineral estate.

The Safford operation’s electrical power is primarily sourced from Tucson Electric Power Company, Arizona Public Service Company and the Luna Energy facility. Although we believe the Safford operation has sufficient water sources to support current operations, we are a party to litigation that may impact our water right claims or rights to continued use of currently available water supplies, which could adversely affect our water supply for the Safford operation. Refer to “Governmental Regulations” above, Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” for further discussion.

Sierrita
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Our wholly owned Sierrita mine is an open-pit copper and molybdenum mining complex that has been in operation since 1959. Sierrita is located in Pima County, Arizona, approximately 20 miles southwest of Tucson and 7 miles west of the town of Green Valley and Interstate Highway 19. The site is accessible by a paved highway and by rail.

The Sierrita mine is a porphyry copper deposit that has oxide, secondary sulfide and primary sulfide mineralization. The predominant oxide copper minerals are malachite, azurite and chrysocolla. Chalcocite is the most important secondary copper sulfide mineral, and chalcopyrite and molybdenite are the dominant primary sulfides.

The Sierrita operation includes a concentrator with a milling design capacity of 100,000 metric tons of ore per day that produces copper and molybdenum concentrate. Sierrita also produces copper from a ROM oxide-leaching system. Cathode copper is plated at the Twin Buttes EW facility, which has a design capacity of approximately 50 million pounds of copper per year. The Sierrita operation also has molybdenum facilities consisting of a leaching circuit, two molybdenum roasters and a packaging facility. The molybdenum facilities process molybdenum concentrate produced by Sierrita, from our other mines and from third-party sources. The available mining fleet consists of twenty-five 235-metric-ton haul trucks loaded by 4 electric shovels with bucket sizes ranging from 34 to 56 cubic meters, which are capable of moving an average of 200,000 metric tons of material per day. Sierrita’s net PP&E and mine development costs at December 31, 2024, totaled $0.9 billion.

Sierrita’s production totaled 165 million pounds of copper and 15 million pounds of molybdenum in 2024, 185 million pounds of copper and 18 million pounds of molybdenum in 2023, and 184 million pounds of copper and 17 million pounds of molybdenum in 2022.

Sierrita is located in a desert environment with rainfall averaging 14 inches per year. The highest bench elevation is 1,387 meters above sea level and the ultimate pit bottom is expected to be 427 meters above sea level. The Sierrita operation, including the adjacent Twin Buttes site, encompasses approximately 47,700 acres, comprising 38,700 acres of fee lands including split estate lands and 9,000 acres of unpatented mining claims held on public mineral estate.

Sierrita receives electrical power through long-term contracts with the Tucson Electric Power Company. Although we believe the Sierrita operation has sufficient water sources to support current operations, we are a party to litigation that may impact our water rights claims or rights to continued use of currently available water supplies, which could
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adversely affect our water supply for the Sierrita operation. Refer to “Governmental Regulations” above, Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” for further discussion.

Miami
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Our wholly owned Miami mine is an open-pit copper mining complex located in Gila County, Arizona, 90 miles east of Phoenix and 6 miles west of the city of Globe on U.S. Highway 60. The site is accessible by a paved highway and by rail.

The Miami mine is a porphyry copper deposit that has leachable oxide and secondary sulfide mineralization. The predominant oxide copper minerals are chrysocolla, copper-bearing clays, malachite and azurite. Chalcocite and covellite are the most important secondary copper sulfide minerals.

Since about 1915, the Miami mining operation had processed copper ore using both flotation and leaching technologies. The design capacity of the SX/EW plant is 200 million pounds of copper per year. Miami is no longer mining ore, but currently produces copper through leaching material already placed on stockpiles. Miami’s net PP&E and mine development costs at December 31, 2024, totaled $13 million.

Miami’s copper production totaled 9 million pounds in 2024, 12 million pounds in 2023 and 11 million pounds in 2022.

Miami is located in a desert environment with rainfall averaging 18 inches per year. The highest bench elevation is 1,390 meters above sea level and mining advanced the pit bottom to an elevation of 810 meters above sea level. Subsequent sloughing of material into the pit has filled it back to an elevation estimated to be 900 meters above sea level. The Miami operation encompasses approximately 14,800 acres, comprising 10,400 acres of fee lands and 4,400 acres of unpatented mining claims held on public mineral estate.

Miami receives electrical power through long-term contracts with the Salt River Project and natural gas through long-term contracts with El Paso Natural Gas as the transporter. We believe the Miami operation has sufficient water sources to support current operations. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

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Chino and Tyrone
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Chino. Our wholly owned Chino mine is an open-pit copper mining complex that has been in operation since 1910. Chino is located in Grant County, New Mexico, approximately 15 miles east of Silver City, along State Highway 180. The mine is accessible by paved roads and by rail.

The Chino mine is a porphyry copper deposit with adjacent copper skarn deposits. There is leachable oxide, secondary sulfide and millable primary sulfide mineralization. The predominant oxide copper mineral is chrysocolla. Chalcocite is the most important secondary copper sulfide mineral, and chalcopyrite and molybdenite are the dominant primary sulfides.

The Chino operation consists of a concentrator with a milling design capacity of 36,000 metric tons of ore per day that produces copper concentrate, and a 150 million pound-per-year SX/EW plant that produces copper cathode from solution generated by ROM leaching. The available mining fleet consists of twenty 240-metric-ton haul trucks loaded by 3 electric shovels with bucket sizes ranging from 31 to 48 cubic meters, which are capable of moving an average of 180,000 metric tons of material per day. Chino’s net PP&E and mine development costs at December 31, 2024, totaled $0.6 billion.

Chino’s copper production totaled 133 million pounds in 2024, 141 million pounds in 2023 and 130 million pounds in 2022.

Chino is located in a desert environment with rainfall averaging 16 inches per year. The highest bench elevation is 2,250 meters above sea level and the ultimate pit bottom is expected to be 1,508 meters above sea level. The Chino operation encompasses approximately 129,700 acres, comprising 111,900 acres of fee lands and 17,800 acres of unpatented mining claims held on public mineral estate.

Chino receives electrical power from the Luna Energy facility and from the open market. We believe the Chino operation has sufficient water sources to support current operations. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

Tyrone. Our wholly owned Tyrone mine is an open-pit copper mining complex and has been in operation since 1967. Tyrone is located in Grant County, New Mexico, 10 miles south of Silver City, along State Highway 90. The site is accessible by paved roads and by rail.

The Tyrone mine is a porphyry copper deposit. Mineralization is predominantly secondary sulfide consisting of chalcocite, with leachable oxide mineralization consisting of chrysocolla.

Copper processing facilities consist of a SX/EW operation with a maximum capacity of approximately 100 million pounds of copper cathode per year. The available mining fleet consists of six 240-metric-ton haul trucks loaded by 1 electric shovel with a bucket size of 47 cubic meters, which is capable of moving an average of 108,000 metric tons of material per day. Tyrone’s net PP&E and mine development costs at December 31, 2024, totaled $0.1 billion.

Tyrone’s copper production totaled 43 million pounds in 2024, 51 million pounds in 2023 and 59 million pounds in 2022.

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Tyrone is located in a desert environment with rainfall averaging 16 inches per year. The highest bench elevation is 2,070 meters above sea level and the ultimate pit bottom is expected to have an elevation of 1,475 meters above sea level. The Tyrone operation encompasses approximately 78,500 acres, comprising 65,500 acres of fee lands and 13,000 acres of unpatented mining claims held on public mineral estate.

Tyrone receives electrical power from the Luna Energy facility and from the open market. We believe the Tyrone operation has sufficient water sources to support current operations. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

Climax and Henderson
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Climax. Our wholly owned Climax mine is an open-pit molybdenum mine that is located 13 miles northeast of Leadville, Colorado, off Colorado State Highway 91 at the top of Fremont Pass. The mine is accessible by paved roads. Climax was placed on care and maintenance status by its previous owner in 1995 and, after being acquired by FMC, began commercial production in 2012.

The Climax ore body is a porphyry molybdenum deposit, with molybdenite as the primary sulfide mineral.

The Climax mine includes a 25,000 metric tons of ore per day mill facility. Climax has the capacity to produce approximately 30 million pounds of molybdenum per year. The majority of the molybdenum concentrate produced is shipped to our Fort Madison, Iowa, processing facility. The available mining fleet consists of thirteen 177-metric-ton haul trucks loaded by 2 hydraulic shovels with bucket sizes of 34 cubic meters, which are capable of moving an average of 90,000 metric tons of material per day. Climax’s net PP&E and mine development costs at December 31, 2024, totaled $1.4 billion.

Climax’s molybdenum production totaled 18 million pounds in 2024, 17 million pounds in 2023 and 21 million pounds in 2022.

The Climax mine is located in a mountainous region. The highest bench elevation is approximately 4,050 meters above sea level and the ultimate pit bottom is expected to have an elevation of approximately 3,100 meters above sea level. This region experiences significant snowfall during the winter months. The Climax operation encompasses approximately 15,100 acres, comprising 14,300 acres of privately owned land and 800 acres of federal claims.

Climax operations receive electrical power through long-term contracts with Xcel Energy and natural gas supply with United Energy Trading (with Xcel as the transporter). We believe the Climax operation has sufficient water sources to support current operations. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

Henderson. Our wholly owned Henderson molybdenum mining complex has been in operation since 1976. Henderson is located 42 miles west of Denver, Colorado, off U.S. Highway 40. Nearby communities include the towns of Empire, Georgetown and Idaho Springs. The Henderson mill site is located 15 miles west of the mine and is accessible from Colorado State Highway 9. The Henderson mine and mill are connected by a 10-mile conveyor tunnel under the Continental Divide and an additional 5-mile surface conveyor. The tunnel portal is located 5 miles east of the mill.
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The Henderson mine is a porphyry molybdenum deposit, with molybdenite as the primary sulfide mineral.

The Henderson operation consists of a block-cave underground mining complex feeding a concentrator with a design capacity of approximately 32,000 metric tons per day. Henderson has the capacity to produce approximately 15 million pounds of molybdenum per year. The majority of the molybdenum concentrate produced is shipped to our Fort Madison, Iowa, processing facility. The available underground mining equipment fleet consists of fifteen 9-metric-ton load-haul-dump (LHD) units and seven 73-metric-ton haul trucks, which deliver ore to a gyratory crusher feeding a series of 3 overland conveyors to the mill stockpiles. Henderson’s net PP&E and mine development costs at December 31, 2024, totaled $0.3 billion.

Henderson’s molybdenum production totaled 12 million pounds in 2024, 13 million pounds in 2023 and 12 million pounds in 2022.

The Henderson mine is located in a mountainous region with the main access shaft at 3,180 meters above sea level. The main production levels are currently at elevations of 2,200 and 2,350 meters above sea level. This region experiences significant snowfall during the winter months. The Henderson mine and mill operations encompass approximately 17,200 acres, comprising 13,000 acres of fee lands, 4,200 acres of unpatented mining claims held on public mineral estate and a 50-acre easement with the U.S. Forest Service for the surface portion of the conveyor corridor.

Henderson operations receive electrical power through long-term contracts with Xcel Energy and natural gas supply with United Energy Trading (with Xcel Energy as the transporter). We believe the Henderson operation has sufficient water sources to support current operations. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

South America
At our operations in South America, mine properties and facilities are controlled through mining claims or concessions under the general mining laws of the relevant country. The claims or concessions are owned or controlled by the operating companies in which we or our subsidiaries have a controlling ownership interest. Roads, power lines and aqueducts are controlled by easements.

Cerro Verde
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In September 2024, we purchased 5.3 million shares of Cerro Verde common stock for $210 million, increasing our ownership interest in Cerro Verde to 55.08% from 53.56%. The remaining 44.92% ownership interest in Cerro Verde is held by SMM Cerro Verde Netherlands B.V. (21.0%), Compañia de Minas Buenaventura S.A.A. (19.58%) and other stockholders whose Cerro Verde shares are publicly traded on the Lima Stock Exchange (4.34%).

Cerro Verde is an open-pit copper and molybdenum mining complex that has been in operation since the 1970s. Cerro Verde is located 20 miles southwest of Arequipa, Peru. Prior to being acquired in 1994 by a predecessor of Phelps Dodge, the mine was previously operated by the Peru government. The property is located at latitude 16.53 degrees south and longitude 71.58 degrees west using the WGS 84 coordinate system. The site is accessible by paved highways. Cerro Verde’s copper cathode and concentrate production that is not sold locally is transported approximately 70 miles by truck and by rail to the Port of Matarani for shipment to international markets. Molybdenum concentrate is transported by truck to either the Ports of Callao or Matarani for shipment.
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The Cerro Verde mine is a porphyry copper deposit that has oxide, secondary sulfide and primary sulfide mineralization. The predominant oxide copper minerals are brochantite, chrysocolla, malachite and copper “pitch.” Chalcocite and covellite are the most important secondary copper sulfide minerals. Chalcopyrite and molybdenite are the dominant primary sulfides.

Cerro Verde’s operation includes 2 concentrating facilities with an annual average permitted milling capacity of 409,500 metric tons of ore per day (and the ability to annually treat up to 10% more for a total of 450,450 metric tons of ore per day). As a result of several efficiency initiatives implemented over the past several years, in 2024, Cerro Verde’s 2 concentrators were able to achieve a combined average milling rate of 415,500 metric tons of ore per day in 2024. Cerro Verde also operates a 100,000-metric-ton-per-day ROM leach system coupled with SX/EW leaching facilities, which have a production capacity of approximately 200 million pounds of copper per year.

The available fleet consists of fifty-four 300-metric-ton haul trucks, ninety-one 250-metric-ton haul trucks (8 of which are currently on standby) and 8 leased 380-metric-ton haul trucks loaded by 14 electric shovels with bucket sizes ranging from 33 to 57 cubic meters. This fleet is capable of moving an average of approximately 1,000,000 metric tons of material per day. Cerro Verde’s net PP&E and mine development costs at December 31, 2024, totaled $5.8 billion.

Cerro Verde’s production totaled 0.9 billion pounds of copper and 20 million pounds of molybdenum in 2024, 1.0 billion pounds of copper and 22 million pounds of molybdenum in 2023, and 1.0 billion pounds of copper and 23 million pounds of molybdenum in 2022.

Cerro Verde is located in a desert environment with rainfall averaging less than two inches per year and is in an active seismic zone. The highest bench elevation is 2,768 meters above sea level and the ultimate pit bottom is expected to be 1,538 meters above sea level. The Peru general mining law and Cerro Verde’s mining stability agreement grant the surface rights of mining concessions located on government land. Government land obtained after 1997 must be leased or purchased. Cerro Verde has a mining concession covering approximately 175,500 acres, including 61,500 acres of surface rights and access to 14,600 acres granted through an easement from the Peru National Assets Office, plus 151 acres of owned property, and 1,065 acres of rights-of-way outside the mining concession area leased from both government agencies and private parties.

Cerro Verde currently receives electrical power, including hydro-generated power, under long-term contracts with ElectroPerú S.A. and Engie Energía Peru S.A. During 2023, Cerro Verde entered into a new power purchase agreement that is expected to transition its electric power to fully renewable energy sources in 2026.

Water for our Cerro Verde processing operations comes from renewable sources through a series of storage reservoirs on the Río Chili watershed that collect water primarily from seasonal precipitation and from wastewater collected from the city of Arequipa and treated at a wastewater treatment plant originally constructed and currently operated by Cerro Verde. We believe the Cerro Verde operation has sufficient water sources to support current operations, but we are closely monitoring ongoing weather patterns. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.

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El Abra
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We have a 51% ownership interest in El Abra, and the remaining 49% interest is held by the state-owned copper enterprise Corporación Nacional del Cobre de Chile.

El Abra is an open-pit copper mining complex that has been in operation since 1996. El Abra is located 47 miles north of Calama in Chile’s El Loa province of the northern Chilean region of Antofagasta. The site is accessible by paved highways and by rail.

The El Abra mine is a porphyry copper deposit that has sulfide and oxide mineralization. The predominant primary sulfide copper minerals are bornite and chalcopyrite. There is a minor amount of secondary sulfide mineralization as chalcocite. The oxide copper minerals are chrysocolla and pseudomalachite. There are lesser amounts of copper bearing clays and tenorite.

The El Abra operation consists of a SX/EW facility with a capacity of 500 million pounds of copper cathode per year from a 115,000-metric-ton-per-day crushed leach circuit and a ROM leaching operation. The available fleet consists of twenty-three 242-metric-ton haul trucks loaded by 4 electric shovels with buckets ranging in size from 29 to 41 cubic meters, which are capable of moving 217,000 metric tons of material per day. El Abra’s net PP&E and mine development costs at December 31, 2024, totaled $0.8 billion.

El Abra’s copper production totaled 219 million pounds in 2024, 217 million pounds in 2023 and 202 million pounds in 2022.

We have completed substantial drilling and evaluations to define a large sulfide resource that would support a potential major mill project similar to the large-scale concentrator at Cerro Verde. We are preparing data for a potential submission of an environmental impact statement by year-end 2025, subject to ongoing stakeholder engagement and economic evaluations. Preliminary estimates, which remain under review, indicate that the project economics would be supported using an incentive copper price of less than $4.00 per pound. The decision of whether to proceed and timing of the potential project will take into account overall copper market conditions, required permitting and other factors.

El Abra is located in a desert environment with rainfall averaging less than one inch per year and is in an active seismic zone. The highest bench elevation is 4,225 meters above sea level and the ultimate pit bottom is expected to be 3,340 meters above sea level. El Abra controls a total of approximately 183,700 acres of mining claims covering the ore deposit, stockpiles, process plant, and water wellfield and pipeline. El Abra also has land surface rights for the road between the processing plant and the mine, the water wellfield, power transmission lines and for the water pipeline from the Salar de Ascotán aquifer.

El Abra currently receives electrical power under a long-term contract with Engie Energía Chile S.A. Water for our El Abra processing operations currently comes from the continued pumping of groundwater from the Salar de Ascotán aquifer pursuant to regulatory approval. We believe El Abra has sufficient water sources to support current operations, although we are evaluating options for water infrastructure alternatives to provide options to extend existing operations and support a future expansion. Refer to “Governmental Regulations” above and Item 1A. “Risk Factors” for further discussion.
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Indonesia
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Ownership. PT-FI is a limited liability company organized under the laws of the Republic of Indonesia. On December 21, 2018, we completed the transaction with the Indonesia government regarding PT-FI’s long-term mining rights and share ownership (the 2018 Transaction). Following the 2018 Transaction, we have a 48.76% share ownership in PT-FI and the remaining 51.24% share ownership is collectively held by PT Mineral Industri Indonesia (MIND ID), an Indonesia state-owned enterprise, and PT Indonesia Papua Metal Dan Mineral (formerly known as PT Indocopper Investama), which is expected to be owned by MIND ID and the provincial/regional government in Central Papua, Indonesia.

IUPK. Concurrent with closing the 2018 Transaction, the Indonesia government granted PT-FI a special mining business license (IUPK) to replace its former contract of work. Under the terms of the IUPK, PT-FI has been granted an extension of mining rights through 2031, with rights to extend mining rights through 2041, subject to PT-FI completing the construction of additional domestic smelting and refining capacity in Indonesia and fulfilling its defined fiscal obligations to the Indonesia government. The IUPK, and related documentation, contains legal and fiscal terms and is legally enforceable through 2041. In addition, we, as a foreign investor, have rights to resolve investment disputes with the Indonesia government through international arbitration.

Pursuant to regulations issued during 2024, PT-FI is eligible to apply for an extension of its mining rights beyond 2041, provided certain conditions are met, including ownership of integrated downstream facilities that have entered the operational stage; domestic ownership of at least 51% and agreement with a state-owned enterprise for an additional 10% ownership; and commitments for additional exploration and increases in refining capacity, each as approved by the Ministry of Energy and Mineral Resources. Application for extension may be submitted at any time up to one year prior to the expiration of the current IUPK. PT-FI expects to apply for an extension during 2025, pending agreement with MIND ID on a purchase and sale agreement for the transfer in 2041 of an additional 10% interest in PT-FI. An extension would enable continuity of large-scale operations for the benefit of all stakeholders and provide growth options through additional resource development opportunities in the highly attractive Grasberg minerals district.

Refer to Item 1A. “Risk Factors” and Notes 10 and 11 for discussion of PT-FI’s IUPK, export licenses and risks associated with our Indonesia operations.

Downstream Processing Facilities. In connection with the 2018 Transaction, PT-FI agreed to expand its domestic smelting and refining capacity. The new smelter and PT Smelting will smelt and refine copper concentrate from PT-FI, and the PMR will process anode slimes from the new smelter and PT Smelting. Once its new downstream processing facilities are operational, PT-FI’s operations will be fully integrated.

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During 2024, construction of PT-FI’s new smelter in Eastern Java, Indonesia was completed. In October 2024, during start-up activities, a fire occurred that required a temporary suspension of smelting operations to complete repairs. Procurement of long-lead items is advanced and repairs are scheduled to be completed by mid-2025, and PT-FI expects ramp-up to full capacity to be achieved by year-end 2025.

As part of start-up activities, PT-FI commenced gold production from its new PMR in December 2024. The PMR has the design capacity to refine all precious metals from PT-FI’s new smelter as well as from PT Smelting.

Pursuant to the terms of its IUPK regarding force majeure events, PT-FI has requested approval from the Indonesia government to permit exports of copper concentrate in 2025 until the required repairs of its new smelter following the October 2024 fire incident and full ramp-up are complete. Based on discussions with the Indonesia government, PT-FI expects to re-commence exports of copper concentrate during first-quarter 2025, and pursuant to current regulations, would be required to pay a 7.5% export duty on all copper concentrate exports during 2025.

Refer to “Smelting Facilities and Other Mining Properties” below, Item 1A. “Risk Factors,” MD&A and Notes 10 and 11 for additional discussion of PT-FI’s new downstream processing facilities.

Grasberg Minerals District. PT-FI operates in the remote highlands of the Sudirman Mountain Range in the province of Central Papua, Indonesia, which is on the western half of the island of New Guinea. Since 1967, we and our predecessors have been the only operator of exploration and mining activities in the approximately 24,600-acre operating area. The operating area is accessible by coastal portsite facilities on the Arafura Sea and by the Timika airport. The project site is located at latitude 4.08 degrees south and longitude 137.12 degrees east using the WGS 84 coordinate system. The project area includes a 70-mile main service road from portsite to the mill complex. PT-FI’s net PP&E and mine development costs at December 31, 2024, including the new downstream processing facilities, totaled $21.1 billion.

Production from the Grasberg minerals district totaled 1.8 billion pounds of copper and 1.9 million ounces of gold in 2024, 1.7 billion pounds of copper and 2.0 million ounces of gold in 2023, and 1.6 billion pounds of copper and 1.8 million ounces of gold in 2022.

Over a multi-year investment period, PT-FI has successfully commissioned three large-scale underground mines in the Grasberg minerals district (Grasberg Block Cave, Deep Mill Level Zone (DMLZ) and Big Gossan). Milling rates for ore from these underground mines averaged 208,400 metric tons of ore per day in 2024, 198,300 metric tons of ore per day in 2023 and 192,600 metric tons of ore per day in 2022. Production from these underground mines is expected to continue through 2041 and an extension of PT-FI’s operating rights beyond 2041 would extend the lives of these mines. In December 2024, PT-FI completed construction of a new copper cleaner circuit, a mill recovery project to enhance recoveries and optimize concentrate production, with commissioning underway. Refer to Item 1A. “Risk Factors” for discussion of risks associated with development projects and underground mines.

PT-FI plans to transition its existing energy source from coal to natural gas, which would meaningfully reduce PT-FI’s Scope 1 GHG emissions at the Grasberg minerals district. The majority of PT-FI’s planned investments in a new gas-fired combined cycle facility are expected to be incurred over the next three years, at a cost of approximately $1 billion, which represents an incremental cost of $0.4 billion compared to previously planned investments to refurbish the existing coal units. Once complete, PT-FI’s dual-fuel power plant and the new gas-fired combined cycle facility will be fueled by natural gas, supplied by a floating liquefied natural gas storage and regassification unit.

A combination of naturally occurring mountain streams and water derived from our underground operations provides water for our operations. Our Indonesia operations are in an active seismic zone and experience average annual rainfall of approximately 200 inches.

Grasberg Block Cave Underground Mine
The Grasberg Block Cave ore body is the same ore body historically mined from the surface in the Grasberg open pit. Undercutting, drawbell construction and ore extraction activities in the Grasberg Block Cave underground mine continue to track expectations. As of December 31, 2024, the Grasberg Block Cave underground mine had 469 open drawbells.

Ore milled from the Grasberg Block Cave underground mine averaged 133,800 metric tons per day in 2024, 117,300 metric tons per day in 2023 and 103,300 metric tons per day in 2022.
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The Grasberg Block Cave fleet consists of approximately 530 pieces of mobile equipment. The primary mining equipment directly associated with production and development includes an available fleet of 96 LHD units and 16 haul trucks. Each production LHD unit typically carries approximately 11 metric tons of ore and transfers ore into the rail haulage system. The Grasberg Block Cave has an automated rail haulage system currently operating with 14 locomotives and 143 ore wagons that haul the ore to 3 gyratory crushers located underground. Each ore wagon typically carries 35 metric tons. The crushed ore is conveyed to surface stockpiles for processing.

DMLZ Underground Mine
The DMLZ ore body lies below the depleted Deep Ore Zone underground mine at the 2,590-meter elevation and represents the downward continuation of mineralization in the Ertsberg East Skarn system and neighboring Ertsberg porphyry.

Hydraulic fracturing operations have been effective in managing rock stresses and pre-conditioning the cave following mining-induced seismic activity experienced from time to time. As of December 31, 2024, the DMLZ underground mine had 174 open drawbells.

Ore milled from the DMLZ underground mine averaged 64,900 metric tons per day in 2024, 75,900 metric tons per day in 2023 and 76,300 metric tons per day in 2022.

The DMLZ fleet consists of approximately 310 pieces of mobile equipment, which includes 59 LHD units and 26 haul trucks used in production and development activities. Each production LHD unit typically carries approximately 9 metric tons of ore and transfers ore into the truck haulage system. The haul trucks have a capacity of 55 to 60 metric tons and load ore from chutes fed by the LHDs and transfer it to one of two gyratory crushers. The crushed ore is conveyed to surface stockpiles for processing.

Big Gossan Underground Mine
The Big Gossan ore body lies underground and adjacent to the current mill site. It is a tabular, near vertical ore body with approximate dimensions of 1,200 meters along strike and 800 meters down dip with varying thicknesses from 20 meters to 120 meters. The mine utilizes a blasthole stoping method with delayed paste backfill. Stopes of varying sizes are mined and the ore dropped down passes to a truck haulage level. Trucks are chute loaded and transport the ore to a jaw crusher. The crushed ore is then hoisted vertically via a two-skip production shaft to a level where it is loaded onto a conveyor belt. The belt carries the ore to one of the main underground conveyors where the ore is transferred and conveyed to the surface stockpiles for processing.

Ore milled from the Big Gossan underground mine averaged 8,000 metric tons per day in 2024, 7,900 metric tons per day in 2023 and 7,600 metric tons per day in 2022.

The Big Gossan fleet consists of approximately 70 pieces of mobile equipment, which includes 7 LHD units and 10 haul trucks used in development and production activities.

Kucing Liar Underground Mine
Long-term mine development activities are ongoing for PT-FI’s Kucing Liar deposit in the Grasberg minerals district. Kucing Liar is expected to produce over 7 billion pounds of copper and 6 million ounces of gold between 2029 and the end of 2041, and an extension of PT-FI’s operating rights beyond 2041 would extend the life of the project. Development activities commenced in 2022 and are expected to continue over an approximate 10-year timeframe. Capital investments for Kucing Liar are estimated to total $4 billion over the next 7 to 8 years (averaging approximately $0.5 billion per annum). Approximately $0.6 billion has been incurred through December 31, 2024. At full operating rates, annual production from Kucing Liar is expected to approximate 560 million pounds of copper and 520 thousand ounces of gold, providing PT-FI with sustained long-term, large-scale and low-cost production. Kucing Liar will benefit from substantial shared infrastructure and PT-FI’s experience and long-term success in block-cave mining.

Description of Indonesia Ore Bodies. Our Indonesia ore bodies are located within and around two main igneous intrusions, the Grasberg monzodiorite and the Ertsberg diorite. The host rocks of these ore bodies include both carbonate and clastic rocks that form the ridge crests and upper flanks of the Sudirman Range, and the igneous rocks of monzonitic to dioritic composition that intrude them. The igneous-hosted ore bodies (the Grasberg Block Cave and portions of the DMLZ) occur as vein stockworks and disseminations of copper sulfides, dominated by chalcopyrite and, to a lesser extent, bornite. The sedimentary-rock hosted ore bodies (portions of the DMLZ and Kucing Liar and all of the Big Gossan) occur as “magnetite-rich, calcium/magnesian skarn” replacements, whose
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location and orientation are strongly influenced by major faults and by the chemistry of the carbonate rocks along the margins of the intrusions.

The copper mineralization in these skarn deposits is dominated by chalcopyrite, but higher bornite concentrations are common. Moreover, gold occurs in significant concentrations in all of the district’s ore bodies, though rarely visible to the naked eye. These gold concentrations usually occur as inclusions within the copper sulfide minerals, though, in some deposits, these concentrations can also be strongly associated with pyrite.

The following diagram indicates the relative elevations (in meters) of our reported Indonesia ore bodies.
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The following map, which encompasses an area of 42 square kilometers, indicates the relative positions and sizes of our reported Indonesia ore bodies and their locations.
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Smelting Facilities and Other Mining Properties
PT-FI’s New Downstream Processing Facilities. PT-FI’s new smelter and PT Smelting (see further discussion below) will smelt and refine copper concentrate from PT-FI, and the PMR will process anode slimes from the new smelter and PT Smelting. Once its new downstream processing facilities are operational, PT-FI’s operations will be fully integrated.

PT-FI’s new greenfield smelter in Eastern Java, Indonesia has a capacity to process approximately 1.7 million metric tons of copper concentrate per year. During start-up activities, a fire occurred in October 2024, requiring a temporary suspension of smelting operations to complete repairs. Procurement of long-lead items is advanced and repairs are scheduled to be completed by mid-2025. PT-FI expects restoration, repair and replacement costs to approximate $100 million, which are expected to be mostly offset through recovery under construction insurance programs. PT-FI expects ramp-up to full capacity to be achieved by year-end 2025.

As part of start-up activities, PT-FI commenced gold production from its new PMR in December 2024.

PT Smelting. PT Smelting, an Indonesian joint venture between PT-FI and MMC, owns a copper smelter and refinery in Gresik, Indonesia. In December 2023, PT Smelting completed the expansion of its capacity by 30% to process approximately 1.3 million metric tons of copper concentrate per year. The project was funded by PT-FI with loans totaling $254 million that converted to equity effective June 30, 2024, increasing PT-FI’s ownership in PT Smelting to 66% from 39.5%. As discussed in Note 2, PT-FI continues to account for its investment in PT Smelting under the equity method.

Beginning in 2023, PT-FI’s commercial arrangement with PT Smelting changed from a copper concentrate sales agreement to a tolling arrangement. Under the arrangement, PT-FI pays PT Smelting a tolling fee (which PT-FI records as production costs in the consolidated statements of income) to smelt and refine its copper concentrate and PT-FI retains title to all products for sale to unaffiliated third parties (i.e., there are no further sales to PT Smelting). Refer to MD&A and Note 2 for further discussion.

PT Smelting’s copper anode production from its smelter totaled 398,200 metric tons in 2024, 251,300 metric tons in 2023 and 316,700 metric tons in 2022. Copper cathode production from its refinery totaled 335,200 metric tons in 2024, 212,000 metric tons in 2023 and 268,400 metric tons in 2022.

PT Smelting’s major scheduled maintenance turnarounds (which approximate 30 days to complete) are expected to occur every two years, with short-term maintenance turnarounds in the interim. PT Smelting completed an 18-day maintenance turnaround during October 2022, a 72-day shutdown in July 2023 associated with its expansion project and a 7-day shutdown in November 2023 to complete final tie-in of the expansion project. The next maintenance turnaround is scheduled for mid-year 2025.

Atlantic Copper. Our wholly owned Atlantic Copper smelter and refinery is located on land concessions from the Huelva, Spain, port authorities, which are scheduled to expire in 2038.

The smelter has a design capacity to process approximately 300,000 metric tons of copper per year, and the refinery has a capacity to process 286,000 metric tons of copper per year. Atlantic Copper’s copper anode production from its smelter totaled 247,600 metric tons in 2024, 261,900 metric tons in 2023 and 215,000 metric tons in 2022. Copper cathode production from its refinery totaled 254,400 metric tons in 2024, 260,300 metric tons in 2023 and 218,400 metric tons in 2022.

During 2024, Atlantic Copper purchased 30% of its concentrate from our copper mining operations (15% from South America operations, 13% from Indonesia operations and 2% from the North America copper mines) and 70% from third parties.

Atlantic Copper’s major maintenance turnarounds typically occur approximately every eight years, with shorter-term maintenance turnarounds in the interim. Atlantic Copper completed a 17-day maintenance turnaround in 2024 and a 78-day major maintenance turnaround in 2022.

Atlantic Copper is developing an e-material recycling project as a result of the significant and continued
growth in electronic waste material. Atlantic Copper’s existing smelting and refining facilities provide synergies to recycle this type of material, and the project, which is expected to commence operations in 2026, would include an addition of a smelting furnace and associated equipment to recover copper, gold, silver, palladium, tin, nickel and
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platinum from electronic materials. Atlantic Copper estimates that the initial project capital will approximate $435 million.

Miami Smelter. We own and operate a smelter at our Miami mining operation in Arizona. The smelter has been operating for over 100 years and has been upgraded numerous times during that period to implement new technologies, improve production and comply with air quality requirements.

The Miami smelter processes copper concentrate primarily from our North America copper mines. Concentrate processed through the smelter totaled 840,600 metric tons in 2024, 810,900 metric tons in 2023 and 781,000 metric tons in 2022, and copper anode production from the smelter totaled 214,000 metric tons in 2024, 222,000 metric tons in 2023 and 202,000 metric tons in 2022. In addition, because sulfuric acid is a by-product of smelting concentrate, the Miami smelter is also the most significant source of sulfuric acid for our North America leaching operations.

Major maintenance turnarounds are anticipated to occur approximately every three to four years for the Miami smelter. We performed a major maintenance turnaround during 2021 and the next major maintenance turnaround is scheduled for mid-year 2025, for which we expect to incur maintenance charges and idle facility costs of approximately $85 million.

Rod & Refining Operations. Our Rod & Refining operations consist of conversion facilities located in North America, including a refinery in El Paso, Texas, and rod mills in El Paso, Texas and Miami, Arizona. We refine our copper anode production from our Miami smelter at our El Paso refinery. The El Paso refinery has the potential to operate at an annual production capacity of approximately 410,000 metric tons of copper cathode, which is sufficient to refine all of the copper anode we produce at our Miami smelter. Copper cathode production from the El Paso refinery totaled 221,300 metric tons in 2024, 217,800 metric tons in 2023 and 208,900 metric tons in 2022. Our El Paso refinery also produces nickel carbonate, copper telluride and autoclaved slimes material containing gold, silver, platinum and palladium.

Molybdenum Conversion Facilities. We process molybdenum concentrate at our conversion plants in the U.S. and Europe into such products as technical-grade molybdic oxide, ferromolybdenum, pure molybdic oxide, ammonium molybdates and molybdenum disulfide. We operate molybdenum roasters in Sierrita, Arizona; Fort Madison, Iowa; and Rotterdam, the Netherlands, and we operate a molybdenum pressure-leach plant in Bagdad, Arizona. We also produce ferromolybdenum for customers worldwide at our conversion plant located in Stowmarket, United Kingdom.

Other North America Copper Mines. We have five non-operating copper mines – Ajo, Bisbee, Tohono, Twin Buttes and Christmas, which are located in Arizona – that have been on care and maintenance status for several years and would require new or updated environmental studies, new permits, and additional capital investment, which could be significant, to return them to operating status.

MINING DEVELOPMENT PROJECTS AND EXPLORATION ACTIVITIES

In 2024, capital expenditures totaled $4.8 billion (including $2.1 billion for major mining projects – primarily for underground development activities in the Grasberg minerals district – and $1.2 billion for PT-FI’s new downstream processing facilities).

We have several projects and potential opportunities to expand production volumes, extend mine lives and develop large-scale underground ore bodies. As further discussed in MD&A, our near-term major development projects will focus on the underground development activities in the Grasberg minerals district. Considering the long-term nature and large size of our development projects, actual costs and timing could vary from estimates. Additionally, in response to market conditions, the timing of our expenditures will continue to be reviewed. We continue to review our mine development and processing plans to maximize the value of our mineral reserves.

Additionally, based on the current reserve life through 2041, full development of PT-FI’s underground mineral reserves at the Grasberg minerals district is expected to require approximately $4 billion (most of which will be incurred over the next 8 years) of capital expenditures at our processing facilities to optimize the handling of underground ore from the Grasberg Block Cave, DMLZ and Kucing Liar deposits. Increases in power loads at these processing facilities and the underground mines are expected to require additional power generation and as such, PT-FI is planning investments in a new gas-fired combined cycle facility. The majority of PT-FI’s planned
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investments in a new gas-fired combined cycle facility are expected to be incurred over the next three years, at a cost of approximately $1 billion, which represents an incremental cost of $0.4 billion compared to previously planned investments to refurbish the existing coal units. Once complete, PT-FI’s dual-fuel power plant and the new gas-fired combined cycle facility will be fueled by natural gas, supplied by a floating liquefied natural gas storage and regassification unit.

In 2024, exploration spending associated with our mining operations totaled $113 million. Our mining exploration activities are primarily associated with our existing mines, focusing on opportunities to expand mineral reserves and resources to support development of additional future production capacity. Exploration results continue to indicate opportunities for significant future potential reserve additions at our existing properties.

Refer to Item 1A. “Risk Factors” for further discussion of risks associated with mine development projects and exploration activities, and PT-FI’s IUPK.

SOURCES AND AVAILABILITY OF ENERGY, NATURAL RESOURCES AND RAW MATERIALS

Our copper mining operations require significant amounts of energy, principally diesel, electricity, coal and natural gas, most of which is obtained from third parties under long-term contracts. In 2024, energy represented 16% of our copper mine site operating costs, including purchases of approximately 270 million gallons of diesel fuel; approximately 8,550 gigawatt hours of electricity at our North America and South America copper mining operations (we generate all of our power at our Indonesia mining operation); approximately 750 thousand metric tons of coal for our coal power plant in Indonesia; and approximately 2 million MMBtu (million British thermal units) of natural gas at certain of our North America mines. Based on current cost estimates, energy is expected to approximate 16% of our copper mine site operating costs for the year 2025.

Our mining operations also require significant quantities of water for mining, ore processing and related support facilities. The loss of water rights for any of our mines, in whole or in part, or shortages of water to which we have rights, could require us to curtail or shut down mining operations. For a further discussion of risks and legal proceedings associated with the availability of water, refer to “Governmental Regulations” above, Item 1A. “Risk Factors” and Item 3. “Legal Proceedings.”

Sulfuric acid is used in the SX/EW process and is produced as a by-product of the smelting process at our smelters and from our sulfur burners at the Safford mine. Sulfuric acid needs in excess of the sulfuric acid produced by our operations are purchased from third parties.

For further discussion of risks associated with various input costs, refer to Item 1A. “Risk Factors.”

HUMAN CAPITAL

We are committed to promoting the health, safety and well-being of our workforce and striving to further strengthen our commitment to promoting an inclusive, diverse and agile workplace. We believe our global workforce is the foundation of our success. Our Board of Directors (Board) oversees our policies and implementation programs that govern our approach to human capital management, with the Corporate Responsibility Committee (CRC) having oversight of health and safety matters and the Compensation Committee having oversight of other human capital matters, including those relating to workforce recruitment, retention and development, pay equity, and inclusion and diversity.

Workforce
At December 31, 2024, we had approximately 28,500 employees (13,900 in North America, 6,900 in South America, 6,600 in Indonesia and 1,100 in Europe and other locations). We also had contractors that employed personnel at many of our operations at various times throughout 2024, including approximately 32,200 in Indonesia (approximately 8,100 at PT-FI’s new downstream processing facilities and approximately 24,100 at the Grasberg minerals district), 25,500 in North America, 6,300 at our South America mining operations and 1,700 in Europe and other locations. Certain of these contractors work on projects that are temporary in nature and fluctuate from year to year.

Approximately 28% of our global employee population is covered by collective labor agreements (CLAs). In North America, our employees are not covered by a CLA. Rather, our hourly, full-time employees at our active North
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America sites elect to work directly with management using our Guiding Principles, which outline how we work together to achieve our collective goals within the values of the company.

We prioritize open engagement with our employees and, where applicable, union leadership to negotiate and uphold labor agreements effectively. Prolonged strikes and other work stoppages can adversely affect our business, our workforce and regional stakeholders. In 2024, there were no strikes or lockouts at any of our operations, and Cerro Verde completed new multi-year CLAs with its two unions, PT-FI completed a new two-year CLA with its three unions and Atlantic Copper completed a new CLA with its three unions.

A summary of employees covered by CLAs on December 31, 2024, including the number of employees covered and the expiration date of the applicable CLA, follows:

LocationNumber of UnionsNumber of
 Employees Covered by a CLA		Expiration Date
PT-FI – Indonesia
32,849 March 2026
Cerro Verde – Peru
23,544 August 2028 and August 2029
El Abra – Chile
2915 April 2026
Atlantic Copper – Spain
3525 December 2026

Stowmarket – United Kingdom
141 May 2026

In 2024, our employees formerly covered by a CLA in Rotterdam, The Netherlands eliminated their union representation and decided to negotiate directly with management through their internal works council. An employee benefits agreement replaced the CLA and is expected to be negotiated again in March 2025.

Health and Safety
Our highest priority is the health, safety and well-being of our employees and contractors. We also work to promote our safety-first values with our suppliers and in the communities where we operate. We believe that health and safety considerations are integral to, and fundamental for, all other functions in our organization, and we understand the health and safety of our workforce is critical to our operational efficiency and long-term success. Our global health and safety strategy, “Safe Production Matters,” is focused on fatality prevention, eliminating systemic root causes of incidents and continuous improvement through robust management systems, which are supported by leaders empowering our teams to work safely. Our culture of leading by example at all levels of the organization and our Safe Production Matters strategy underpin our Fatal Risk Management (FRM) program. The goal of our FRM program is to achieve zero workplace fatalities by strengthening preventative measures and raising awareness to fatal risks and the measures necessary to mitigate them.

We further seek to prevent fatalities and high-risk incidents by leveraging technology to support safe work practices in the field and data analytics to identify opportunities for improvement. Our framework for managing risks and compliance obligations is certified company-wide in accordance with the ISO 45001 Health and Safety Management System (ISO 45001), most recently certified in January 2023. ISO 45001 requires third-party site-level verification of requirements, with an overall goal of preventing fatalities and reducing safety incidents.

As part of our commitment to providing a healthy and safe workplace, we strive to provide the training, tools and resources needed so our workforce can identify risks and consistently apply effective controls. We share information and key learnings about potential fatal events (PFEs), high-risk incidents and best practices throughout the company, and we engage with industry peers and professional organizations to learn and continuously improve our health and safety program. Our corporate team communicates safety performance to executive management regularly, including reviews of high-risk, potential fatal and fatal incidents. The CRC provides input on the overall direction of our health and safety programs and reviews safety statistics, trends and incident investigation reports. In the event of a fatal incident, executive management and the Chair of the CRC are notified immediately, and we review and discuss all fatal incident investigations with the CRC and the Board.

Our objective is to achieve zero workplace fatalities and to decrease injuries and occupational illnesses. We measure our safety performance through regularly established benchmarks, including the industry-established Total Recordable Incident Rate (TRIR), and our company-established PFEs, both of which include employees and contractors company-wide. Regrettably, we had two work-related fatalities in 2024 and one work-related fatality in
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2023. In addition, we had 30 PFEs in 2024 and 46 PFEs in 2023. Our TRIR per 200,000 man-hours worked was 0.52 in 2024 and 0.60 in 2023.

Employee Engagement, Training and Development
We aim to recruit and retain talented employees with diverse perspectives by offering, among other things, competitive compensation and benefits and pathways for career advancement. We prioritize a highly engaged, agile workforce and, in addition to physical and psychological safety, we aim to support the overall health and well-being of our workforce by providing access to health and wellness programs, and offering opportunities for flexible work schedules, where practicable, among other programs.

We continued to face challenges in 2024 with an increasingly competitive and tight labor market, specifically in North America, and we remain committed to assessing our recruitment and training and development programs to adapt to the changing labor market and our employee needs.

To support the advancement of our employees, we conduct regular strategic talent reviews and leadership planning. We offer training and development programs to encourage the growth of internal talent and to continue to promote a strong and experienced management pipeline. We leverage both formal and informal programs to identify, foster and retain top talent at both the corporate and operations levels. We expect our talent management processes and corresponding training and development programs will continue to mature and evolve in line with our commitment to continuous improvement.

Workplace Culture
We are dedicated to cultivating a company culture prioritizing safety, respect, inclusivity, and representation of the diverse communities in which we operate. As a global organization that operates in regions of varying ethnic, religious and cultural backgrounds, we value and prioritize inclusion and diversity within our workforce. A broad range of experience, knowledge, background, culture and heritage drives innovation, enhances operational performance and improves relationships with stakeholders.

We are often the largest employer in our local communities, which are typically in remote areas, and hiring locally is a commitment we make to the communities surrounding our operations and to our host countries. We retain expatriate expertise for managerial and technical roles when the required expertise is not available in local communities. We offer cultural awareness training to expatriates and inpatriates for new locations.

We strive for, promote and foster a workplace where everyone feels a sense of belonging, is treated with respect and their opinions are valued. We believe an inclusive environment gives our people the confidence to speak up, share ideas that drive innovation and achieve operational excellence. We believe our inclusive environment is the foundation of our high-performance culture and is paramount to the long-term sustainable success of our business.

We are also committed to providing equal pay for equal work regardless of gender, race, ethnicity or any other characteristic protected by applicable law. We periodically conduct internal compensation reviews to identify and address, as appropriate, possible pay gaps, which cannot be explained through performance, distribution of jobs, experience, time in role and other legitimate business-related factors.

Additional information regarding our workforce can be found in our Annual Report on Sustainability, which is available on our website and updated annually.

Refer to Item 1A. “Risk Factors” for further information on human capital matters.

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COMMUNITY AND HUMAN RIGHTS

We have adopted policies that govern our working relationships with the communities where we operate and that are designed to guide our practices and programs in a manner that respects human rights and the culture of the local people impacted by our operations. In addition, global regulations with regard to human rights and environmental due diligence in supply chains require us to identify, and to prevent, or at least mitigate, adverse impacts on human rights and the environment.

We continue to make significant expenditures on community development, health, education, training and cultural programs, which include:

•comprehensive job training programs
•clean water and sanitation projects
•public health programs, including malaria control
•agricultural assistance programs
•small and medium enterprise development programs
•basic education programs
•advanced education scholarships
•cultural resources promotion and preservation programs
•community infrastructure development
•charitable donations

In 2000, we endorsed the joint U.S. State Department-British Foreign Office Voluntary Principles on Security and Human Rights (Voluntary Principles). We participated in developing these Voluntary Principles with other major natural resource companies and international human rights organizations and they are incorporated into our Human Rights Policy. The Voluntary Principles provide guidelines for our security programs, including interaction with host-government security personnel, private security contractors and our internal security employees.

Our Human Rights Policy reflects our commitment to implementing the United Nations Guiding Principles on Business and Human Rights. We conduct site-level human rights impact assessments (HRIAs) at our global operations, which help us to embed human rights considerations into our business practices. We completed HRIAs at Cerro Verde in 2024, our PT-FI Grasberg operations in 2023, Arizona operations in 2022, El Abra in 2021 and New Mexico operations in 2018. We are at the mid-way point of our HRIA at PT-FI’s new downstream processing facilities and plan to initiate our HRIA at our Colorado operations later in 2025. We continue to participate in a multi-industry human rights working group to gain insight from peer companies and experts in the field to learn how best practices are evolving.

We believe that our social and economic development programs are responsive to the issues raised by the local communities near our areas of operation and help us maintain good relations with the surrounding communities and avoid disruptions of mining operations. As part of our ongoing commitment to our community stakeholders, we have made and expect to continue making investments in certain social programs, including in-kind support and administration, across our global operations from time to time. Over the last three years, charges for these investments have averaged approximately $185 million per year. Nevertheless, social and political instability in the areas of our operations may adversely impact our mining operations. Refer to Item 1A. “Risk Factors” for further discussion.

South America. Cerro Verde has provided a variety of community support projects over the years. Following engagements with regional and local governments, civic leaders and development agencies, Cerro Verde constructed a potable water treatment plant to serve Arequipa. In addition, the development of a water storage network was financed by Cerro Verde and a distribution network was financed by the Cerro Verde Civil Association.

In 2015, Cerro Verde completed construction of a wastewater treatment plant for the city of Arequipa, which, in addition to supplementing existing water supplies to support Cerro Verde’s concentrator expansion, also improves the local water quality, enhances agriculture products grown in the area and reduces the risk of waterborne illnesses. In addition to these projects, Cerro Verde annually makes significant community development investments in the Arequipa region.

Security Matters. Consistent with our operating permits in Peru and our commitment to protect our employees and property, we have taken steps to provide a safe and secure working environment. As part of its security program,
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Cerro Verde maintains its own internal security department. Both employees and contractors perform functions such as protecting company facilities, monitoring shipments of supplies and products, assisting in traffic control and aiding in emergency response operations. The security department receives human rights and Voluntary Principles training annually. Cerro Verde’s costs for its internal civilian security department totaled $8 million in both 2024 and 2023 and $7 million in 2022.

Cerro Verde, like all businesses and residents of Peru, relies on the Peru government for the maintenance of public order, upholding the rule of law and the protection of personnel and property. The Peru government is responsible for employing police personnel and directing their operations. Cerro Verde has limited public security forces in support of its operation, with the arrangement defined through an Inter-institutional Cooperation Agreement with the Peru National Police. Cerro Verde’s share of support costs for government-provided security approximated $1 million in 2024, 2023 and 2022. Refer to Item 1A. “Risk Factors” for further discussion of security risks in Peru.

Indonesia. PT-FI provides funding and technical assistance to support various community development programs in areas such as health, education, economic development and local infrastructure. In 1996, PT-FI established a social investment fund with the aim of contributing to social and economic development in the Mimika Regency. Prior to 2019, the fund was mainly managed by the Amungme and Kamoro Community Development Organization, a community-led institution. In 2019, a new foundation, the Amungme and Kamoro Community Empowerment Foundation (Yayasan Pemberdayaan Masyarakat Amungme dan Kamoro, or YPMAK), was established, and in 2020, PT-FI appointed YPMAK to assist in distributing a significant portion of PT-FI’s funding to support the development and empowerment of the local Indigenous Papuan people. YPMAK is governed by a Board of Governors consisting of seven representatives, including four from PT-FI.

In addition, since 2001, PT-FI has voluntarily established and contributed to land rights trust funds administered by Amungme and Kamoro representatives that focus on socioeconomic initiatives, human rights and environmental issues.

PT-FI is committed to the continued funding of YPMAK programs and the land rights trust funds, as well as other local-community development initiatives, making annual investments in public health, education, and local economic development. PT-FI recorded charges totaling $141 million in 2024 and $123 million in both 2023 and 2022 to production and delivery costs for social and economic development programs.

Security Matters. Consistent with our ongoing commitment to protect our employees and property, we have taken steps to provide a safe and secure working environment. As part of its security program, PT-FI maintains its own internal civilian security department. Both employees and contractors perform functions such as protecting company facilities, monitoring shipments of supplies and products, assisting in traffic control and aiding in emergency response operations. The security department receives human rights training annually.

PT-FI’s costs for its internal civilian security department totaled $49 million in 2024, $51 million in 2023 and $50 million in 2022.

PT-FI, like all businesses and residents of Indonesia, relies on the Indonesia government for the maintenance of public order, upholding the rule of law and protection of personnel and property. The Grasberg minerals district has been designated by the Indonesia government as one of Indonesia’s national vital objects. This designation results in the police and, to a lesser extent, the military playing a significant role in protecting the area of our operations. The Indonesia government is responsible for employing police and military personnel and directing their operations. As part of pre-deployment, all military and police personnel receive human rights training.

From the outset of PT-FI’s operations, the Indonesia government has looked to PT-FI to provide logistical and infrastructure support and assistance for these necessary services because of the limited resources of the Indonesia government and the remote location of and lack of development in the province of Central Papua. PT-FI’s financial support of the Indonesia government security institutions assigned to PT-FI’s operations area represents a prudent response to PT-FI’s requirements and commitments to protect its workforce and property, better ensuring that personnel are properly fed and lodged and have the logistical resources to patrol PT-FI’s roads and secure its area of operations. In addition, the provision of such support is consistent with our philosophy of responsible corporate citizenship and reflects our commitment to pursue practices that protect and respect human rights.
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PT-FI’s support costs for the government-provided security totaled $24 million in 2024 and $25 million in both 2023 and 2022. This supplemental support consists of various infrastructure and other costs, including food, housing, fuel, travel, vehicle repairs, allowances to cover incidental and administrative costs, and community assistance programs conducted by the military and police. Refer to Item 1A. “Risk Factors” for further discussion of security risks in Indonesia.

MINING PRODUCTION AND SALES DATA
Years Ended December 31,
ProductionSales
COPPER (millions of recoverable pounds)
202420232022202420232022
(FCX’s net interest in %)        
North America        
Morenci (72%)a
505 575 636  517 578 639 
Safford (100%)249 245 285 246 250 281 
Sierrita (100%)165 185 184 167 183 186 
Bagdad (100%)146 146 165  146 148 169 
Chino (100%)133 141 130  133 143 127 
Tyrone (100%)43 51 59  44 53 59 
Miami (100%)9 12 11 10 12 11 
Other (100%)(4)(5)(3) (6)(6)(3)
Total North America1,246 1,350 1,467  1,257 1,361 1,469 
South America        
Cerro Verde (55.08%)b
949 985 974 958 988 964 
El Abra (51%)219 217 202 219 212 198 
Total South America1,168 1,202 1,176 1,177 1,200 1,162 
Indonesia        
Grasberg minerals district (48.76%)c
1,800 1,660 1,567 1,632 1,525 1,582 
Consolidated4,214 4,212 4,210 4,066 
d
4,086 
d
4,213 
d
Less noncontrolling interests1,465 1,414 845 1,384 1,344 840 
Net2,749 2,798 3,365 2,682 2,742 3,373 
Average realized price per pound$4.21 $3.85 $3.90 
GOLD (thousands of recoverable ounces)
        
(FCX’s net interest in %)
North America (100%)19 15 13 20 16 12 
Indonesia (48.76%)c
1,861 1,978 1,798 1,817 1,697 1,811 
Consolidated1,880 1,993 1,811  1,837 1,713 1,823 
Less noncontrolling interests953 952 337 931 808 339 
Net927 1,041 1,474 906 905 1,484 
Average realized price per ounce$2,418 $1,972 $1,787 
MOLYBDENUM (millions of recoverable pounds)
        
(FCX’s net interest in %)
Climax (100%)18 17 21 N/AN/AN/A
Henderson (100%)12 13 12 N/AN/AN/A
North America copper mines (100%)a
30 30 29 N/AN/AN/A
Cerro Verde (55.08%)b
20 22 23 N/AN/AN/A
Consolidated80 82 85 78 81 75 
Less noncontrolling interest9 10 11 9 10 10 
Net71 72 74 69 71 65 
Average realized price per pound$21.77 $24.64 $18.71 
a.Amounts are net of Morenci’s joint venture partners’ undivided interest.
b.Our economic interest in Cerro Verde is 55.08%, and prior to September 2024 it was 53.56%.
c.Our economic interest in PT-FI is 48.76% and prior to 2023, it approximated 81% (refer to Note 2 for further discussion).
d.Consolidated sales volumes exclude purchased copper of 158 million pounds in 2024, 103 million pounds in 2023 and 124 million pounds in 2022.

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SELECTED OPERATING DATA
 Years Ended December 31, 
 20242023202220212020
CONSOLIDATED MINING 
Copper (millions of recoverable pounds)       
Production 4,214 4,212 4,210 3,843 3,206  
Sales, excluding purchases4,066 4,086 4,213 3,807 3,202  
Average realized price per pound$4.21 $3.85 $3.90 $4.33 $2.95 
Gold (thousands of recoverable ounces)       
Production 1,880 1,993 1,811 1,381 857 
Sales, excluding purchases1,837 1,713 1,823 1,360 855 
Average realized price per ounce$2,418 $1,972 $1,787 $1,796 $1,832 
Molybdenum (millions of recoverable pounds)       
Production 80 82 85 85 76 
Sales, excluding purchases78 81 75 82 80 
Average realized price per pound$21.77 $24.64 $18.71 $15.56 $10.20 
NORTH AMERICA COPPER MINES
Operating Data, Net of Joint Venture Interestsa
       
Copper (millions of recoverable pounds)       
Production 1,246 1,350 1,467 1,460 1,418 
Sales, excluding purchases1,257 1,361 1,469 1,436 1,422 
Average realized price per pound$4.29 $3.93 $4.08 $4.30 $2.82 
Molybdenum (millions of recoverable pounds)       
Production 30 30 29 34 33  
100% Operating Data       
Leach operations       
Leach ore placed in stockpiles (metric tons per day)609,400 692,000 676,400 665,900 714,300  
Average copper ore grade (%)0.20 0.23 0.29 0.29 0.27  
Copper production (millions of recoverable pounds)842 941 1,019 1,056 1,047  
Mill operations       
Ore milled (metric tons per day)311,700 308,500 294,200 269,500 279,700  
Average ore grade (%):       
Copper0.30 0.32 0.37 0.38 0.35  
Molybdenum0.02 0.02 0.02 0.03 0.02  
Copper recovery rate (%)83.2 81.8 81.8 81.2 84.1  
Copper production (millions of recoverable pounds)601 633 695 649 647  
SOUTH AMERICA OPERATIONS 
Copper (millions of recoverable pounds)       
Production 1,168 1,202 1,176 1,047 979  
Sales1,177 1,200 1,162 1,055 976  
Average realized price per pound$4.16 $3.82 $3.80 $4.34  $3.05  
Molybdenum (millions of recoverable pounds)       
Production 20 22 23 21 19  
Leach operations       
Leach ore placed in stockpiles (metric tons per day)164,300 191,200 163,000 163,900 160,300  
Average copper ore grade (%)0.42 0.35 0.35 0.32 0.35  
Copper production (millions of recoverable pounds)295 317 302 256 241  
Mill operations      
Ore milled (metric tons per day)415,500 417,400 409,200 380,300 331,600 
Average ore grade (%):      
Copper0.33 0.34 0.32 0.31 0.34 
Molybdenum0.01 0.01 0.01 0.01 0.01 
Copper recovery rate (%)83.6 81.3 85.3 87.3 84.3 
Copper production (millions of recoverable pounds)873 885 874 791 738 
a.Amounts are net of Morenci’s joint venture partners’ undivided interest.

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SELECTED OPERATING DATA (Continued)
 Years Ended December 31, 
 20242023 202220212020
INDONESIA OPERATIONS
Copper (millions of recoverable pounds)      
Production 1,800 1,660 1,567 1,336 809 
Sales1,632 1,525 1,582 1,316 804 
Average realized price per pound$4.19 $3.81  $3.80 $4.34 $3.08 
Gold (thousands of recoverable ounces)      
Production 1,861 1,978 1,798 1,370 848 
Sales1,817 1,697 1,811 1,349 842 
Average realized price per ounce$2,418 $1,972 $1,787 $1,796 $1,832 
Mill operations      
Ore milled (metric tons per day)208,400 198,300 192,600 151,600 87,700 
Average ore grade:      
Copper (%)1.27 1.22 1.19 1.30 1.32 
Gold (grams per metric ton)1.00 1.12 1.05 1.04 1.10 
Recovery rates (%):      
Copper88.4 89.7 90.0 89.8 91.9 
Gold76.9 77.9 77.7 77.0 78.1 
MOLYBDENUM MINES
Ore milled (metric tons per day)28,000 27,900 26,100 21,800 20,700 
Average molybdenum ore grade (%)0.16 0.15 0.18 0.19 0.17 
Molybdenum production (millions of recoverable pounds)30 30 33 30 24 

MINERAL RESERVES

Our estimates of mineral reserves have been prepared using industry accepted practice and conform to the disclosure requirements of Subpart 1300 of SEC Regulation S-K. Proven and probable mineral reserves were determined from the application of relevant modifying factors to geological data to establish an operational, economically viable mine plan. The estimates are based on mapping, drilling, sampling, assaying and evaluation methods generally applied in the mining industry. Mineral reserves, as used in the mineral reserve data presented here, means the economically mineable part of a measured or indicated resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted. Proven mineral reserves mean the economically mineable part of a measured mineral resource, from geological evidence revealed in outcrops, trenches, workings or drill holes with grades and/or quality estimates from detailed, closely spaced sampling, and geologic characterization that defines the size, shape, depth and mineral content to a high degree of confidence. Probable mineral reserves means the economically mineable part of an indicated mineral resource, for which quantity and grade are estimated from information similar to that used for measured mineral resources where the samples are farther apart, and the geological characterization is adequate. Probable mineral reserves can also include remaining portions of a measured mineral resource. The degree of assurance, although lower than that for proven mineral reserves, is high enough to assume continuity between points of observation.

Our estimates of recoverable proven and probable mineral reserves are prepared by and are the responsibility of our employees. These estimates are reviewed and verified regularly by independent experts in mining, geology and reserve determination. Our mineral reserve estimates are based on the latest available geological and geotechnical studies. We conduct ongoing studies of our ore bodies to evaluate economic values and to manage risk. We revise our mine plans and estimates of recoverable proven and probable mineral reserves as required in accordance with the latest available studies. Refer to Item 1A. “Risk Factors” for discussion of risks associated with our estimates of proven and probable mineral reserves.

Estimated recoverable proven and probable mineral reserves at December 31, 2024, were determined using metal price assumptions of $3.25 per pound for copper, $1,600 per ounce for gold and $12.00 per pound for molybdenum. For the three-year period ended December 31, 2024, LME copper settlement prices averaged $4.00 per pound, London PM gold prices averaged $2,044 per ounce and the weekly average price for molybdenum quoted by Platts Metals Daily averaged $21.41 per pound.
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The estimated recoverable proven and probable mineral reserves presented in the table below represent the estimated metal quantities from which we expect to be paid after application of estimated metallurgical recoveries and smelter recoveries, where applicable.
 Estimated Recoverable Proven and Probable Mineral Reserves at December 31, 2024
Coppera
(billion pounds)
Gold
(million ounces)
Molybdenum
(billion pounds)
North America41.6 0.6 2.51 
South Americab
28.4 — 0.66 
Indonesiac
27.0 22.4 — 
Consolidated basisd
97.0 23.0 3.16 
Net equity intereste
70.2 11.5 2.87 
Note: May not foot because of rounding.
a.Estimated consolidated recoverable copper reserves include 1.4 billion pounds in leach stockpiles and 0.3 billion pounds in mill stockpiles (refer to “Mill and Leach Stockpiles” for further discussion).
b.Excludes the El Abra mill project discussed in “Operations – South America” (estimated potential addition of approximately 20 billion recoverable pounds of copper in concentrate and cathode).
c.Estimated recoverable proven and probable mineral reserves from Indonesia reflect estimates of minerals that can be recovered through the life of the IUPK in 2041. We believe an extension would provide additional material reserves. Refer to Note 11 for discussion of PT-FI’s IUPK.
d.Consolidated mineral reserves represent estimated metal quantities after reduction for joint venture partner interests at the Morenci mine in North America (refer to Note 2 for further discussion of our Morenci joint venture). Excluded from the table above are our estimated recoverable proven and probable silver reserves of 318 million ounces, which were determined using $20 per ounce.
e.Net equity interest mineral reserves represent estimated consolidated metal quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries). Excluded from the table above are our estimated recoverable proven and probable silver reserves of 213 million ounces.
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Estimated Recoverable Proven and Probable Mineral Reserves
at December 31, 2024
  Proven Mineral ReservesProbable Mineral Reserves
  Million Metric TonsAverage Ore GradeMillion Metric TonsAverage Ore Grade
 FCX’sProcessingFCX’s100%CopperGold MolySilverFCX’s100%CopperGold MolySilver
 InterestMethodInterestBasis%g/t %g/tInterestBasis%g/t %g/t
North America             
Morenci
72%
Mill525 730 0.33 — 0.02 — 50 69 0.32 — 0.03 — 
 Crushed leach63 88 0.36 — — — 1 2 0.31 — — — 
 ROM leach1,787 2,481 0.17 — — — 313 435 0.15 — — — 
Bagdad
100%
Mill2,032 2,032 0.35 — 
a
0.02 1.46 380 380 0.33 — 
a
0.02 1.36 
 ROM leach11 11 0.34 — — — 7 7 0.26 — — — 
Safford, including Lone Star
100%
Crushed leach659 659 0.43 — — — 87 87 0.41 — — — 
Sierrita
100%
Mill1,824 1,824 0.23 — 
a
0.03 1.08 382 382 0.25 — 
a
0.02 1.16 
Chino, including Cobre
100%
Mill201 201 0.49 0.05 — 0.92 100 100 0.52 0.05 — 0.96 
 ROM leach61 61 0.24 — — — 8 8 0.25 — — — 
Tyrone
100%
ROM leach62 62 0.19 — — — 7 7 0.21 — — — 
Henderson
100%
Mill31 31 — — 0.16 — 13 13 — — 0.16 — 
Climax
100%
Mill130 130 — — 0.15 — 11 11 — — 0.10 — 
  7,385 8,309 1,361 1,502 
South America            
Cerro Verde
55.08%
Mill347 629 0.36 — 0.02 1.90 1,755 3,186 0.34 — 0.01 1.79 
 ROM leach10 17 0.41 — — — 34 62 0.19 — — — 
El Abra
51%
Crushed leach232 454 0.48 — — — 29 57 0.39 — — — 
 ROM leach45 89 0.25 — — — 6 11 0.18 — — — 
  633 1,189 1,824 3,316 
Indonesia   
Grasberg Block Cave
48.76%
Mill93 191 1.27 0.90 — 3.48 257 528 0.89 0.58 — 3.61 
DMLZ
48.76%
Mill37 77 0.92 0.74 — 4.07 122 250 0.68 0.55 — 3.45 
Big Gossan
48.76%
Mill10 20 2.43 1.03 — 15.15 14 28 2.10 0.90 — 12.68 
Kucing Liarb
48.76%
Mill49 100 1.17 1.03 — 6.16 131 268 1.08 0.91 — 5.55 
  189 388 524 1,074 
Total FCX – 100% Basis
 9,886 5,893 
Total FCX – Consolidated basisc
8,963 5,751 
Total FCX – Net equity interestd
8,207 3,708 
Note: Totals may not foot because of rounding.
a.Amounts not shown because of rounding.
b.PT-FI has commenced long-term mine development activities for the Kucing Liar deposit. See “Operations – Indonesia” for discussion of Kucing Liar capital investments.
c.Consolidated reserves represent estimated quantities after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
d.Net equity interest represents estimated consolidated quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).

The reserve table above and the tables on the following pages utilize the abbreviations described below:
 
•g/t – grams per metric ton
•Moly – Molybdenum
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Estimated Recoverable Proven and Probable Mineral Reserves
at December 31, 2024 (continued)
Proven and Probable
  Million Metric TonsAverage Ore Grade
Recoveriesa
 FCX’sProcessingFCX’s100%CopperGold MolySilverCopperGoldMolySilver
 InterestMethodInterestBasis%g/t %g/t%%%%
North America           
Morenci
72%
Mill575 799 0.33 — 0.02 — 82.8 — 44.1 — 
 Crushed leach64 90 0.36 — — — 83.2 — — — 
 ROM leach2,100 2,916 0.17 — — — 49.7 — — — 
Bagdad
100%
Mill2,412 2,412 0.35 — 
b
0.02 1.44 84.2 59.1 77.1 49.3 
 ROM leach18 18 0.31 — — — 43.8 — — — 
Safford, including Lone Star
100%
Crushed leach746 746 0.43 — — — 70.1 — — — 
Sierrita
100%
Mill2,206 2,206 0.23 — 
b
0.03 1.10 81.2 59.1 78.0 49.3 
Chino, including Cobre
100%
Mill301 301 0.50 0.05 — 0.93 79.5 77.9 — 78.5 
 ROM leach69 69 0.25 — — — 37.4 — — — 
Tyrone
100%
ROM leach69 69 0.19 — — — 57.8 — — — 
Henderson
100%
Mill44 44 — — 0.16 — — — 87.8 — 
Climax
100%
Mill141 141 — — 0.15 — — — 88.8 — 
  8,746 9,811   
South America    
Cerro Verde
55.08%
Mill2,102 3,815 0.34 — 0.01 1.81 85.6 — 54.4 44.9 
 ROM leach43 79 0.24 — — — 48.9 — — — 
El Abra
51%
Crushed leach261 511 0.47 — — — 50.3 — — — 
 ROM leach51 100 0.24 — — — 39.3 — — — 
  2,457 4,505 
Indonesia  
Grasberg Block Cave
48.76%
Mill351 719 0.99 0.66 — 3.57 85.1 67.3 — 58.4 
DMLZ
48.76%
Mill159 326 0.74 0.60 — 3.60 83.0 77.8 — 63.4 
Big Gossan
48.76%
Mill23 48 2.23 0.95 — 13.69 91.4 68.5 — 63.6 
Kucing Liarc
48.76%
Mill180 369 1.10 0.94 — 5.72 79.2 55.5 — 45.7 
  713 1,462 
Total FCX – 100% Basis
 15,779          
Total FCX – Consolidated basisd
14,714 
Total FCX – Net equity intereste
11,916 
Note: Amounts may not equal the sum of proven and probable mineral reserves as presented on the previous page because of rounding. In addition, totals may not foot because of rounding.
a.Recoveries are net of estimated mill and smelter losses.
b.Amounts not shown because of rounding.
c.PT-FI has commenced long-term mine development activities for the Kucing Liar deposit. See “Operations – Indonesia” for discussion of Kucing Liar capital investments.
d.Consolidated reserves represent estimated quantities after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
e.Net equity interest represents estimated consolidated quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).
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Estimated Recoverable Proven and Probable Mineral Reserves
at December 31, 2024 (continued)
   Recoverable Mineral Reserves
   CopperGoldMolySilver
 FCX’sProcessingbillionmillionbillionmillion
 InterestMethodlbs.ozs.lbs.ozs.
North America      
Morenci
72%
Mill4.8 — 0.17 — 
  Crushed leach0.6 — — — 
  ROM leach5.4 — — — 
Bagdad
100%
Mill15.7 0.2 0.86 55.2 
  ROM leach0.1 — — — 
Safford, including Lone Star
100%
Crushed leach4.9 — — — 
Sierrita
100%
Mill9.2 0.1 0.96 38.4 
Chino, including Cobre
100%
Mill2.6 0.4 — 7.1 
  ROM leach0.1 — — — 
Tyrone
100%
ROM leach0.2 — — — 
Henderson
100%
Mill— — 0.14 — 
Climax
100%
Mill— — 0.40 — 
   43.6 0.6 2.53 100.6 
Recoverable metal in stockpilesa
 1.1 — 
b
0.03 0.2 
100% operations 44.7 0.6 2.55 100.8 
Consolidated 41.6 0.6 2.51 100.8 
Net equity interest 41.6 0.6 2.51 100.8 
South America      
Cerro Verde
55.08%
Mill24.6 — 0.65 99.4 
  ROM leach0.2 — — — 
El Abra
51%
Crushed leach2.6 — — — 
  ROM leach0.2 — — — 
   27.7 — 0.65 99.4 
Recoverable metal in stockpilesa
 0.7 — 0.01 0.8 
100% operations 28.4 — 0.66 100.2 
Consolidated 28.4 — 0.66 100.2 
Net equity interest 15.5 — 0.36 55.2 
Indonesia      
Grasberg Block Cave
48.76%
Mill13.4 10.3 — 48.3 
DMLZ
48.76%
Mill4.4 4.9 — 23.9 
Big Gossan
48.76%
Mill2.2 1.0 — 13.5 
Kucing Liarc
48.76%
Mill7.1 6.2 — 31.0 
100% operations 27.0 22.4 — 116.6 
Consolidated 27.0 22.4 — 116.6 
Net equity interest 13.2 10.9 — 56.8 
Total FCX –  100% basis
 100.1 23.0 3.21 317.5 
Total FCX –  Consolidated basisd
 97.0 23.0 3.16 317.5 
Total FCX –  Net equity intereste
 70.2 11.5 2.87 212.8 
Note: Totals may not foot because of rounding.
a.Refer to “Mill and Leach Stockpiles” for additional information.
b.Amounts not shown because of rounding.
c.PT-FI has commenced long-term mine development activities for the Kucing Liar deposit. See “Operations – Indonesia” for discussion of Kucing Liar capital investments.
d.Consolidated mineral reserves represent estimated metal quantities after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
e.Net equity interest mineral reserves represent estimated consolidated metal quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).

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The table below summarizes changes in estimated recoverable copper, gold and molybdenum in mineral reserves between December 31, 2023 and 2024, for our material properties:
Estimated Recoverable Mineral Reserves at 100% Basis
Copper
(billion lbs.)		Gold
(million ozs.)		Molybdenum
(billion lbs.)
MorenciCerro VerdeGrasberg minerals districtGrasberg minerals districtMorenciCerro Verde
Mineral reserves as of December 31, 2023a
12.6 27.0 29.0 23.9 0.23 0.68 
Production(0.7)(0.9)(1.8)(1.9)— 
b
(0.02)
Adjustmentsc
(0.8)(0.8)(0.1)0.3 (0.06)— 
b
Mineral reserves as of December 31, 2024a
11.1 25.2 27.0 22.4 0.17 0.66 
Year-over-year percentage change(12)%(7)%(7)%(6)%(26)%(3)%
Estimated Recoverable Mineral Reserves at Net Equity Basis
Copper
(billion lbs.)		Gold
(million ozs.)		Molybdenum
(billion lbs.)
MorenciCerro VerdeGrasberg minerals districtGrasberg minerals districtMorenciCerro Verde
(72%)
(55.08%)d
(48.76%)(48.76%)(72%)
(55.08%)d
Mineral reserves as of December 31, 2023a
9.1 14.5 14.1 11.6 0.17 0.36 
Production(0.5)(0.5)(0.9)(0.9)— 
b
(0.01)
Adjustmentsc
(0.6)— 
b,e
(0.1)0.2 (0.04)0.01 
e
Mineral reserves as of December 31, 2024a
8.0 13.9 13.2 10.9 0.12 0.36 
Year-over-year percentage change(12)%(4)%(6)%(6)%(29)%— %
Note: Totals may not foot because of rounding.
a.Includes estimated recoverable metals contained in stockpiles. Refer to “Mill and Leach Stockpiles” for additional information.
b.Amounts not shown because of rounding.
c.The downward adjustments at Morenci are primarily the result of mine plan changes and updated geologic models, partly offset by increased leach recovery assumptions. The downward adjustments at Cerro Verde are primarily the result of updated geologic modeling. The adjustments at the Grasberg minerals district are primarily the result of mine design changes.
d.FCX’s interest in Cerro Verde is 55.08%, and prior to September 2024 it was 53.56%.
e.Includes the impact of the increase in FCX’s ownership percentage in 2024.

After accounting for production, changes to the estimates of mineral reserves and mineral resources for the Morenci mine and Grasberg minerals district were not material as compared to the previously filed Technical Report Summaries for each of these properties. After accounting for production, changes to the estimate of mineral reserves for the Cerro Verde mine were not material as compared to the previously filed Technical Report Summary as of December 31, 2022. However, Cerro Verde has had a material change to its estimate of mineral resources (refer to “Mineral Resources” below). See the 2024 Technical Report Summary of Mineral Reserves and Resources for the Cerro Verde mine dated December 31, 2024, filed as Exhibit 96.1 to this Form 10-K.

In defining our open-pit mineral reserves, we apply an “operational cutoff grade” strategy, wherein multiple processing options, throughput constraints, mine development and ore availability are given consideration to maximize the value of our operations. In defining our open-pit mineral resources, internal cutoff grades are applied. The internal cutoff grade is defined for a metric ton of ore as that equivalent copper grade, once produced and sold, that generates sufficient revenue to cover estimated processing and administrative costs. We use “break-even cutoff grades” to define the in-situ mineral reserves and resources for our underground ore bodies. The break-even cutoff grade is defined for a metric ton of ore as that equivalent copper grade, once produced and sold, that generates sufficient revenue to cover all estimated operating and administrative costs associated with our production.

Our copper mines may contain other commercially recoverable metals, such as gold, molybdenum and silver. We value all commercially recoverable metals in terms of a copper equivalent percentage to determine a single cutoff grade. Copper equivalent percentage is used to express the relative value of multi-metal ores in terms of one metal. The calculation expresses the relative value of the ore using estimates of contained metal quantities, metals prices as used for reserve or resource determination, recovery rates, treatment charges and royalties. Our molybdenum properties use a molybdenum cutoff grade.
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The table below shows the minimum cutoff grade for mineral reserves by process for each of our existing ore bodies as of December 31, 2024:

Copper Equivalent Cutoff Grade (%)Molybdenum
Cutoff Grade
(%)
MillCrushed
 Leach		ROM
Leach		Mill
North America  
Morenci0.220.200.03—
Bagdad0.16—0.08—
Safford, including Lone Star—0.14——
Sierrita0.18———
Chino, including Cobre0.22—0.07—
Tyrone——0.02—
Henderson———0.13
Climax———0.05
South America
Cerro Verde0.13—0.08—
El Abra—0.140.12—
Indonesia
Grasberg Block Cave0.55———
DMLZ0.64———
Big Gossan1.70———
Kucing Liar0.64———
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Production Sequencing
The following chart illustrates our current plans for sequencing and producing our proven and probable mineral reserves at each of our ore bodies and the years in which we currently expect production from each ore body and related stockpiles. Our proven and probable mineral reserves in Indonesia reflect estimates of minerals that can be recovered through the end of 2041, and our current mine plan and planned operations are based on the assumption that PT-FI will comply with its obligations under the IUPK and receive the second 10-year extension from 2031 through 2041 (refer to Item 1A. “Risk Factors” and Note 11 for further discussion). We develop our mine plans based on maximizing the net present value from the ore bodies. Significant additional capital expenditures will be required at many of these mines in order to achieve the life-of-mine plans reflected below.
Production Sequencing Chart 1.1.25 V2.jpg
a.The ultimate timing of the start of production at Kucing Liar is dependent upon a number of factors and may vary from the date shown here. Refer to "Operations – Indonesia" for further discussion.

Mill and Leach Stockpiles
Mill and leach stockpiles generally contain lower grade ores that have been extracted from an ore body and are available for metal recovery. Mill stockpiles contain sulfide ores and recovery of metal is through milling, concentrating, smelting and refining or, alternatively, by concentrate leaching. Leach stockpiles contain oxide ores and certain secondary sulfide ores and recovery of metal is through exposure to acidic solutions that dissolve contained copper and deliver it in solution to extraction processing facilities.

Because it is impracticable to determine copper contained in mill and leach stockpiles by physical count, reasonable estimation methods are employed. The quantity of material delivered to mill and leach stockpiles is based on surveyed volumes of mined material and daily production records. Sampling and assaying of blasthole cuttings determine the estimated copper grades of material delivered to mill and leach stockpiles.

Expected copper recoveries for mill stockpiles are determined by metallurgical testing. The recoverable copper in mill stockpiles, once entered into the production process, can be produced into copper concentrate almost immediately.

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Expected copper recoveries for leach stockpiles are determined using small-scale laboratory tests, small- to large-scale column testing (which simulates the production process), historical trends and other factors, including mineralogy of the ore and rock type. Total copper recovery in leach stockpiles can vary significantly from a low percentage to more than 80% depending on several variables, including processing methodology, processing variables, mineralogy and particle size of the rock. For newly placed material on active stockpiles, as much as 80% of total copper recovery may be extracted during the first year, and the remaining copper may be recovered over many years. Processes and copper recoveries for mill and leach stockpiles are monitored regularly, and recovery estimates are adjusted annually based on new information and as related technology and processing methods change. Based on our annual review of mill and leach stockpiles, we increased our estimated consolidated recoverable copper in certain leach stockpiles, net of joint venture interests, by 164 million pounds in 2024, primarily associated with Morenci leach stockpiles, partly offset by a decrease for Safford leach stockpiles.

Following are our stockpiles and the estimated recoverable copper contained within those stockpiles as of December 31, 2024:
Recoverable
FCX’sMillion Metric TonsAverageRecoveriesCopper
InterestFCX’s Interest
100% Basis
Ore Grade (%) (%)(billion lbs.)
Mill stockpiles
Cerro Verde
55.08%
29 53 0.26 65.5 0.2 
North America copper minesa
11 11 0.31 77.1 0.1 
40 64 0.3 
Leach stockpiles
Morenci
72%
5,594 7,775 0.24 0.6 0.3 
Bagdad
100%
506 506 0.25 0.9 — 
b
Safford, including Lone Star
100%
489 489 0.43 4.4 0.2 
Sierrita
100%
650 650 0.15 7.6 0.2 
Miami
100%
498 498 0.39 1.3 0.1 
Chino, including Cobre
100%
1,803 1,803 0.25 2.0 0.2 
Tyrone
100%
1,223 1,223 0.28 1.2 0.1 
Cerro Verde
55.08%
347 629 0.44 4.0 0.2 
El Abra
51%
499 978 0.43 3.0 0.3 
11,609 14,551 1.5 
Total FCX – 100% basis
1.8 
Total FCX – Consolidated basisc
1.7 
Total FCX – Net equity interestd
1.4 
Note: Totals may not foot because of rounding.
a.Our net equity interest in all North America copper mines is 100% except for Morenci, which is 72%.
b.Rounds to less than 0.1 billion pounds of recoverable copper.
c.Consolidated stockpiles represent estimated metal quantities after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
d.Net equity interest represents estimated consolidated metal quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).

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Mineral Resources
In addition to mineral reserves, our properties contain mineral resources that we believe could be brought into production should market conditions warrant. However, permitting and significant capital expenditures may be required before mining of these resources could commence at these properties. A mineral resource is a concentration or occurrence of material of economic interest in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. Such a deposit cannot qualify as recoverable proven and probable mineral reserves until engineering, legal and economic feasibility are confirmed based upon a comprehensive evaluation of development and operating costs, grades, recoveries and other material factors. Mineral resources include measured, indicated and inferred mineral classifications.

•A measured mineral resource is a resource for which the quantity and grade are estimated from detailed, closely spaced sampling, and geologic characterization that defines the size, shape, depth and mineral content to a high degree of confidence.
•An indicated mineral resource is a resource for which quantity and grade are estimated from information similar to that used for measured mineral resources where the samples are farther apart, and the geological characterization is adequate.
•An inferred mineral resource is a resource for which quantity and grade are estimated from information similar to that used for measured and indicated mineral resources, but with limited geological evidence and sampling. Inferred mineral resource grade and mineralization continuity have a lower degree of confidence.

Our estimates of mineral resources have been prepared in accordance with the disclosure requirements of Subpart 1300 of SEC Regulation S-K. No assurance can be given that the estimated mineral resources not included in mineral reserves will become proven and probable mineral reserves.

Estimated mineral resources as presented on the following pages were assessed using prices of $3.75 per pound for copper, $1,700 per ounce for gold, $15 per pound for molybdenum and $20 per ounce for silver. Cutoff grade strategy and expected recoveries used to evaluate mineral resources are consistent with those for mineral reserves but would require additional work to substantiate. Refer to Item 1A. “Risk Factors” for discussion of risks associated with our estimates of mineral resources.
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Table of Contents
Estimated Mineral Resources
at December 31, 2024a
  MeasuredIndicatedInferred
  Million Metric TonsAverage Ore GradeMillion Metric TonsAverage Ore GradeMillion Metric TonsAverage Ore Grade
 FCX’sProcessingFCX’s100%CopperGoldMolySilverFCX’s100%CopperGoldMolySilverFCX’s100%CopperGoldMolySilver
 InterestMethodInterestBasis%g/t%g/tInterestBasis%g/t%g/tInterestBasis%g/t%g/t
North America       
Morenci
72%
Milling607 843 0.29 — 0.02 — 493 685 0.32 — 0.02 — 293 406 0.32 — 0.02 — 
Leaching1,409 1,958 0.17 — — — 750 1,042 0.15 — — — 441 613 0.12 — — — 
Bagdad
100%
Milling380 380 0.31 — 
b
0.02 1.28 487 487 0.26 — 
b
0.02 1.08 534 534 0.18 — 
b
0.01 0.72 
Leaching— 
b
— 
b
0.13 — — — 2 2 0.10 — — — 1 1 0.12 — — — 
Safford, including Lone Star
100%
Milling1,350 1,350 0.38 0.03 — 
b
1.15 1,613 1,613 0.32 0.01 0.01 0.93 432 432 0.27 — 
b
— 
b
0.93 
Leaching557 557 0.29 — — — 410 410 0.29 — — — 118 118 0.28 — — — 
Sierrita
100%
Milling751 751 0.18 — 
b
0.02 0.83 310 310 0.20 — 
b
0.02 0.94 32 32 0.18 — 
b
0.01 0.86 
Chino, including Cobre
100%
Milling147 147 0.35 0.03 0.02 0.68 78 78 0.44 0.04 0.01 0.80 33 33 0.36 0.03 0.01 0.65 
Leaching7 7 0.25 — — — 2 2 0.36 — — — 2 2 0.45 — — — 
Tyrone
100%
Leaching45 45 0.33 — — — 7 7 0.27 — — — 3 3 0.44 — — — 
Henderson
100%
Milling61 61 — — 0.16 — 25 25 — — 0.13 — — — — — — — 
Climax
100%
Milling304 304 — — 0.18 — 53 53 — — 0.11 — 9 9 — — 0.08 — 
Ajo
100%
Milling489 489 0.39 0.07 0.01 0.94 241 241 0.32 0.05 — 
b
0.70 19 19 0.33 0.04 — 
b
1.04 
Cochise/Bisbee
100%
Leaching146 146 0.49 — — — 118 118 0.41 — — — 20 20 0.38 — — — 
Sanchez
100%
Leaching79 79 0.35 — — — 72 72 0.24 — — — 7 7 0.19 — — — 
Tohono
100%
Milling277 277 0.63 0.09 0.01 1.90 31 31 0.67 0.09 0.01 1.72 4 4 0.65 0.07 — 
b
1.44 
Leaching249 249 0.68 — — — 48 48 0.53 — — — 25 25 0.48 — — — 
Twin Buttes
100%
Milling139 139 0.65 0.01 0.04 6.62 10 10 0.63 0.01 0.03 6.31 5 5 0.77 0.01 0.02 8.22 
Leaching55 55 0.24 — — — 15 15 0.21 — — — 7 7 0.25 — — — 
Christmas
100%
Milling67 67 0.53 0.06 — 
b
1.56 231 231 0.37 0.06 — 
b
0.93 39 39 0.40 0.06 — 
b
0.95 
South America  
Cerro Verde
55.08%
Milling46 83 0.29 — 0.01 1.57 944 1,714 0.32 — 0.01 1.70 344 624 0.34 — 0.01 1.80 
Leaching2 4 0.37 — — — 7 13 0.30 — — — 8 14 0.33 — — — 
El Abra
51%
Milling607 1,190 0.43 0.02 0.01 1.42 959 1,880 0.37 0.02 0.01 1.17 862 1,690 0.29 0.01 — 
b
0.92 
Leaching44 86 0.24 — — — 24 46 0.26 — — — 7 14 0.29 — — — 
Indonesia  
Grasberg minerals district
48.76%
Milling197 404 0.77 0.62 — 4.00 1,234 2,530 0.69 0.57 — 3.70 149 306 0.44 0.37 — 2.53 
Total FCX – 100% basis
 9,672 11,662 4,957 
Total FCX – Consolidated basisc
8,887    11,178  4,671 
Total FCX – Net equity interestd
8,016    8,162  3,393 
Note: Totals may not foot because of rounding.
a.Mineral resources are exclusive of mineral reserves.
b.Amounts not shown because of rounding.
c.Consolidated basis represents estimated mineral resources after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
d.Net equity interest represents estimated consolidated mineral resources further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).


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Estimated Mineral Resources
at December 31, 2024a (continued)
  Measured + IndicatedTotal Mineral Resources
  Million Metric TonsMillion Metric TonsAverage Ore Grade
Contained Metalb
Cutoff Gradec
 FCX’sProcessingFCX’s100%FCX’s100%CopperGoldMolySilverCopperGoldMolySilver
 InterestMethodInterestBasisInterestBasis%g/t%g/tbillion lbs.million ozs.billion lbs.million ozs.Grade %
North America    
Morenci
72%
Milling1,100 1,527 1,392 1,934 0.31 — 0.02 — 13.1 — 0.98 — 0.16 
Leaching2,159 3,000 2,600 3,613 0.16 — — — 12.3 — — — 0.03 
Bagdad
100%
Milling868 868 1,401 1,401 0.24 — 
d
0.02 1.00 7.5 0.1 0.56 45.0 0.11 
Leaching2 2 2 2 0.11 — — — — 
d
— — — 0.04 
Safford, including Lone Star
100%
Milling2,963 2,963 3,395 3,395 0.34 0.01 — 
d
1.02 25.2 1.5 0.37 111.0 0.14 
Leaching967 967 1,085 1,085 0.29 — — — 6.9 — — — 0.11 
Sierrita
100%
Milling1,061 1,061 1,093 1,093 0.18 — 
d
0.02 0.86 4.4 0.1 0.52 30.2 0.14 
Chino, including Cobre
100%
Milling225 225 258 258 0.38 0.04 0.01 0.71 2.2 0.3 0.08 5.9 0.18 
Leaching9 9 11 11 0.30 — — — 0.1 — — — 0.06 
Tyrone
100%
Leaching52 52 55 55 0.33 — — — 0.4 — — — 0.04 
Henderson
100%
Milling86 86 86 86 — — 0.15 — — — 0.29 — 0.12 
Climax
100%
Milling357 357 366 366 — — 0.16 — — — 1.33 — 0.05 
Ajo
100%
Milling729 729 748 748 0.36 0.06 0.01 0.87 6.0 1.5 0.11 20.8 0.15 
Cochise/Bisbee
100%
Leaching264 264 284 284 0.45 — — — 2.8 — — — 0.14 
Sanchez
100%
Leaching151 151 159 159 0.29 — — — 1.0 — — — 0.09 
Tohono
100%
Milling308 308 312 312 0.64 0.09 0.01 1.87 4.4 0.9 0.04 18.8 0.17 
Leaching297 297 322 322 0.64 — — — 4.6 — — — 0.14 
Twin Buttes
100%
Milling149 149 155 155 0.65 0.01 0.04 6.65 2.2 — 
d
0.12 33.1 0.19 
Leaching70 70 78 78 0.24 — — — 0.4 — — — 0.01 
Christmas
100%
Milling297 297 337 337 0.41 0.06 — 
d
1.06 3.0 0.6 0.02 11.4 0.22 
South America  
Cerro Verde
55.08%
Milling990 1,797 1,334 2,421 0.32 — 0.01 1.72 17.2 — 0.63 133.8 0.11 
Leaching9 17 17 30 0.32 — — — 0.2 — — — 0.08 
El Abra
51%
Milling1,566 3,070 2,427 4,760 0.36 0.02 0.01 1.14 37.4 2.6 0.81 174.9 0.12 
Leaching68 133 75 147 0.25 — — — 0.8 — — — 0.10 
Indonesia  
Grasberg minerals district
48.76%
Milling1,431 2,934 1,580 3,240 0.67 0.56 — 3.62 48.1 58.3 — 377.5 0.53 
Total FCX – 100% basis
 21,334 26,291 200.3 65.9 5.86 962.4 
Total FCX – Consolidated basise
20,065 24,736  193.2 65.9 5.59 962.4 
Total FCX – Net equity interestf
16,178 19,571  141.9 34.7 4.91 623.2 
Note: Totals may not foot because of rounding. In addition, amounts for “Measured + Indicated” and “Total Mineral Reserves” may not equal the sum of measured, indicated and inferred (as presented on the prior page) because of rounding.
a.Mineral resources are exclusive of mineral reserves.
b.Estimated recoveries are consistent with those for mineral reserves but would require additional work to substantiate.
c.All sites report a % equivalent copper grade except for Climax and Henderson, which report a % molybdenum grade. Our underground mines report a breakeven cutoff grade, and our open-pit mines report an internal cutoff grade.
d.Amounts not shown because of rounding.
e.Consolidated basis represents estimated mineral resources after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
f.Net equity interest represents estimated consolidated mineral resources further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of our ownership in subsidiaries).
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The table below summarizes changes in estimated contained copper, gold and molybdenum in mineral resources between December 31, 2023 and 2024, for our material properties:
Estimated Contained Mineral Resources at 100% Basis
Copper
(billion lbs.)		Gold
(million ozs.)		Molybdenum
(billion lbs.)
MorenciCerro VerdeGrasberg minerals districtGrasberg minerals districtMorenciCerro Verde
Mineral resources as of December 31, 202330.3 23.0 48.2 58.4 1.72 0.78 
Adjustmentsa
(4.8)(5.5)(0.1)(0.2)(0.74)(0.15)
Mineral resources as of December 31, 202425.5 17.5 48.1 58.3 0.98 0.63 
Year-over-year percentage change(16)%(24)%— %— %(43)%(19)%

Estimated Contained Mineral Resources at Net Equity Basis
Copper
(billion lbs.)		Gold
(million ozs.)		Molybdenum
(billion lbs.)
MorenciCerro VerdeGrasberg minerals districtGrasberg minerals districtMorenciCerro Verde
(72%)
(55.08%)b
(48.76%)(48.76%)(72%)
(55.08%)b
Mineral resources as of December 31, 202321.8 12.3 23.5 28.5 1.24 0.42 
Adjustmentsa
(3.5)(2.7)— 
c
(0.1)(0.53)(0.07)
Mineral resources as of December 31, 202418.3 9.6 23.5 28.4 0.71 0.35 
Year-over-year percentage change(16)%(22)%— %— %(43)%(17)%
Note: Totals may not foot because of rounding
a.The downward adjustments at Morenci are primarily the result of higher cost assumptions and updates to the geologic modeling, partially offset by increased leach recovery assumptions. The downward adjustments at Cerro Verde are primarily the result of updates to geologic modeling. The slight downward adjustments at Grasberg minerals district are primarily the result of reassessment of the resource shapes.
b.FCX’s interest in Cerro Verde is 55.08%, and prior to September 2024 it was 53.56%.
c.Rounds to less than 0.1 billion pounds

Internal Controls over the Mineral Reserves and Mineral Resources Estimation Process
We have internal controls over the mineral reserves and mineral resources estimation processes that result in reasonable and reliable estimates aligned with industry practice and reporting regulations. Annually, qualified persons and other employees review the estimates of mineral reserves and mineral resources, the supporting documentation, and compliance with the internal controls and, based on their review of such information, recommend approval to use the mineral reserve and mineral resource estimates to our senior management. Our controls utilize management systems including but not limited to, formal quality assurance and quality control protocols, standardized procedures, workflow processes, supervision and management approval, internal and external reviews and audits, reconciliations, and data security covering record keeping, chain of custody and data storage.

Our systems cover exploration activities, sample preparation and analysis, data verification, mineral processing, metallurgical testing, recovery estimation, mine design and sequencing, and mineral reserve and resource evaluations, with environmental, social and regulatory considerations. Our quality assurance and control protocols over sampling and assaying of drill hole samples include insertion of blind samples consisting of standards, blanks, and duplicates in the primary sample streams, as well as selective sample validation at secondary laboratories.

These controls and other methods help to validate the reasonableness of the estimates. The effectiveness of the controls is reviewed periodically to address changes in conditions and the degree of compliance with policies and procedures. Refer to Item 1A. “Risk Factors” for discussion of risks associated with our estimates of mineral reserves and mineral resources.
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Item 1A. Risk Factors.

This report contains forward-looking statements in which we discuss our potential future performance, operations and projects. Forward-looking statements are all statements other than statements of historical facts, such as plans, projections, or expectations relating to business outlook, strategy, goals or targets; global market conditions; ore grades and milling rates; production and sales volumes; unit net cash costs (credits) and operating costs; capital expenditures; operating plans (including mine sequencing); cash flows; liquidity; PT Freeport Indonesia’s (PT-FI) commissioning, remediation, including expected costs, insurance recovery and timing, and full ramp-up of its new smelter and full production at the precious metals refinery (PMR); potential extension of PT-FI’s special mining business license (IUPK) beyond 2041; export licenses, export duties and export volumes, including PT-FI’s ability to continue exports of copper concentrate until full ramp-up is achieved at its new smelter in Indonesia; timing of shipments of inventoried production; our commitment to deliver responsibly produced copper and molybdenum, including plans to implement, validate and maintain validation of our operating sites under specific frameworks; execution of our energy and climate strategies and the underlying assumptions and estimated impacts on our business and stakeholders related thereto; achievement of 2030 climate targets and 2050 net zero aspiration; improvements in operating procedures and technology innovations and applications; exploration efforts and results; development and production activities, rates and costs; future organic growth opportunities; tax rates; the impact of copper, gold and molybdenum price changes; the impact of deferred intercompany profits on earnings; mineral reserve and mineral resource estimates; final resolution of settlements associated with ongoing legal and environmental proceedings; debt repurchases; and the ongoing implementation of our financial policy and future returns to shareholders, including dividend payments (base or variable) and share repurchases.

We undertake no obligation to update any forward-looking statements, which speak only as of the date made. We caution readers that forward-looking statements are not guarantees of future performance and actual results may differ materially from those anticipated, expected, projected or assumed in the forward-looking statements. Important factors that can cause our actual results to differ materially from those anticipated in the forward-looking statements are included below.

Risk Factor Summary
Investing in our securities involves a high degree of risk and uncertainties. You should carefully consider the risks described below and the information included in other sections of this annual report on Form 10-K, including, but not limited to, Items 1. and 2. “Business and Properties,” Item 1C. “Cybersecurity,” Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk” (MD&A) and Item 3. “Legal Proceedings” prior to investing in our securities. If any of the following risks occur, they may have a material adverse impact on our business, financial performance, stock price, results of operations, operating flexibility, reputation, costs or liabilities and you could lose part or all of your investment. The summary and risks that follow are organized under headings as determined to be most applicable, but such risks also may be relevant to other headings. Moreover, the risk factors described herein are not all of the risks we may face and there may be other risks not presently known to us or that we currently believe are immaterial or general risks that apply to all companies operating in the United States (U.S.) and globally, which may emerge or become material.

Financial risks
•Fluctuations or extended material declines in the market prices of the commodities we produce;
•Fluctuations in price and availability of consumables and components we purchase as well as constraints on supply and logistics, and transportation services;
•Less flexibility because of our debt and other financial commitments;
•Changes in or failure to comply with financial assurance requirements relating to our mine closure reclamation obligations;
•Unanticipated legal proceedings or negative developments in pending legal proceedings or other contingencies; and
•Changes in tax laws and regulations.

International risks
•Geopolitical, economic, regulatory and social risks for our operations; and
•PT-FI’s failure to meet its commitments to achieve the extension of its IUPK.

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Operational risks
•Operational risks inherent in our operations, including underground mining and the ability to smelt and refine;
•Environmental, safety and engineering challenges and risks associated with management of waste rock and tailings;
•Environmental challenges associated with our Indonesia operations;
•Violence, civil and religious strife, and activism;
•Availability of significant quantities of secure water supplies for our operations, including future expansions or development projects;
•Disruptions, damage, failure and implementation and integration risks associated with information and operational technology systems;
•Failure to successfully implement or develop and risks associated with new technologies; and
•Any major public health crisis.

Human capital risks
•Failure to maintain good relations with our workforce and labor disputes or labor unrest; and
•Ability to recruit, retain, develop and advance qualified personnel.

Risks related to development projects and mineral reserves
•Inherent risks associated with development projects and unique risks associated with development of underground mining;
•Ability to maintain or grow our mineral reserves; and
•Inherent uncertainty associated with estimates of mineral reserves and mineral resources.

Regulatory, environmental and social risks
•Compliance with applicable environmental, health and safety laws and regulations;
•Remediation of properties no longer in operation;
•Ability to meet our energy requirements while complying with climate-related regulations and expectations and other energy transition policy changes;
•The physical impacts of climate change on our operations, workforce, communities, biodiversity and ecosystems, supply chains and customers;
•Increasing scrutiny, action and evolving expectations from stakeholders and other third parties with respect to our environmental, social and governance (ESG) practices, performance, commitments and disclosures; and
•Failure or perceived failure to manage relationships with the communities and/or Indigenous Peoples where we operate or that are near our operations.

Risks related to our common stock
•Impact of our holding company structure on our ability to service debt, declare cash dividends, or repurchase shares and debt; and
•Impact of anti-takeover provisions in our charter documents and under Delaware law.

Financial risks

Fluctuations in the market prices of the commodities we produce have caused and may continue to cause significant volatility in our financial performance and in the trading prices of our common stock. Extended material declines in the market prices of such commodities could adversely affect our financial condition and operating plans.

Our financial results are significantly influenced by and vary with fluctuations in the market prices of the commodities we produce, primarily copper and gold, and to a lesser extent molybdenum. Extended material declines in market prices of such commodities could have a material adverse effect on our financial results and the value of our assets, may depress the price of our common stock, and may have a material adverse effect on our ability to comply with financial and other covenants in our debt agreements, service our debt and meet our other
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obligations. For additional information regarding recent macroeconomic and geopolitical factors, see the risk factor below regarding the price and availability of consumables and components we purchase and constraints on supply and logistics, and transportation services.

There has been a history of significant volatility in the commodities markets, including the copper market. Fluctuations in commodities prices are caused by varied and complex factors beyond our control, including global supply and demand and inventory levels; global economic and political conditions (such as election results, level of economic growth, or recession and political or geopolitical tensions and conflicts); national and international regulatory, trade and/or tax policies, including tariffs and other controls on imports and exports; commodities investment activity and speculation; interest rates; current inflation rates and expectations regarding future inflation rates; the strength of the U.S. dollar compared to foreign currencies; the price and availability of substitute products; and changes in technology. Volatility in global economic growth, particularly in developing economies, has the potential to affect adversely future demand and prices for commodities. Geopolitical uncertainty and protectionism can inhibit international trade and negatively impact business confidence, which creates the risk of constraints on our ability to deal in certain markets and has the potential to increase price volatility. For additional information regarding the historical fluctuations of the prices of copper, gold and molybdenum, refer to “Markets” in MD&A.

In addition to the factors discussed above, copper prices may be affected by demand from China, which is currently the largest consumer of refined copper in the world, including as a result of geopolitical uncertainty and tension between the U.S. and China as well as uncertainties about China’s economy. Copper demand and prices also may be affected by industry production, substitution, and thrifting. The adoption and expansion of trade restrictions, or other governmental action related to tariffs and other controls on imports and exports or trade agreements or policies are difficult to predict and could adversely affect copper prices, demand for our products, our costs, our customers, our suppliers and the global economy, which in turn could have a material adverse effect on our business, results of operations or financial condition. We believe long-term fundamentals for copper are favorable with growing demand supported by copper’s critical role in the global transition to renewable power, electric vehicles and other carbon-reduction initiatives, continued urbanization in developing countries, data center and artificial intelligence (AI) developments and growing connectivity globally; however if these markets, industries and transitions do not develop as we expect, or develop more slowly than we expect, future demand and prices for copper may be negatively affected, impacting our business. Copper demand and prices also may be affected by inadequate investment in and limited production from existing copper mining operations, and copper demand globally, including North America, Europe, and Asian countries other than China.

Additional factors affecting gold prices may include purchases and sales of gold by governments and central banks, demand from China and India, two of the world’s largest consumers of gold, and global demand for jewelry containing gold.

If market prices for the primary commodities we produce were to decline and remain low for a sustained period of time, we may have to revise our operating plans, including curtailing or modifying our mining and processing operations, as we have done in the past, and our cash flows, ability to return capital to shareholders and capital expenditure plans could be negatively affected. We may be unable to decrease our costs in an amount sufficient to offset reductions in revenues, in which case we may incur losses, and those losses may be material.

Declines in prices of commodities we sell could also result in metals inventory adjustments and impairment charges for our long-lived assets.

Fluctuations in the price and availability of consumables and components for key machines and equipment we purchase, and constraints on supply and logistics could affect our profitability and operating plans. Further, significant delays or increases in costs affecting transportation services may affect our business.

Consumables and components for key machines and equipment we purchase are subject to price volatility caused by global economic factors that are beyond our control, including, but not limited to, supply chain disruptions, labor shortages, wage pressures, inflation and economic slowdown or recession, as well as fuel and energy costs (for example, the price of diesel), the impact of interruption by fire, power shortages, industrial accidents, hostile acts, cybersecurity attacks, natural disasters or extreme weather events, major public health crises, geopolitical tensions or conflicts (including trade policies such as tariffs and other controls on exports and imports), and foreign currency exchange rate fluctuations.

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Prices of consumables used in our operations, such as natural gas, diesel, coal, other sources of energy, ammonium nitrate, chemical reagents (including sulfuric acid), and steel-related products, and components impact the costs of production at our operations and the costs of development projects. These prices fluctuate and can be volatile. Since 2022, we have experienced price volatility for certain consumables, including diesel fuel, ammonium nitrate and sulfuric acid, and certain components, which has impacted our operating results, and we may experience volatility in the price and availability of other consumables in the future. We also experienced increased costs for equipment, parts and other operating supplies and services. Significant volatility or further increases could have a material adverse effect on our results of operations and could result in material changes to our operating plans or development projects.

Ensuring continuity of supply of such consumables to our operations is critical to our business. We also rely on the availability of components from suppliers for key machines and equipment, which may be impacted by competition demands as well as the availability of input materials in the creation of such equipment. A supplier’s failure to supply consumables or components in a timely manner or to meet our quality, quantity, cost requirements or our technical specifications, or our inability to obtain alternative sources of consumables or components on a timely basis or on terms acceptable to us, could adversely affect our operations. We have also experienced longer lead times on delivery of certain consumables, including fuel, lubricants, ammonium nitrate and sulfuric acid. While these delays did not significantly impact our results for the three years ended December 31, 2024, these delays may continue and could become material. Further, delays and logistical constraints may occur as a result of weather-related impacts or violence, civil and religious strife, and activism at or near our operations or those of our suppliers, as described in the related risk factor below.

Following any interruption to our business, we can require substantial recovery time, experience significant expenditures to resume operations, and lose significant revenues, which could have a material adverse effect on our results of operations. Because we may rely on limited sources and long-lead times for consumables and components for key machines and equipment, a business interruption affecting or requiring such sources would exacerbate any negative consequences to us.

Our business depends on timely inbound transportation of consumables and components we use and outbound transportation of the commodities we produce such as by truck, rail and ocean freight. Any significant increase in the cost of or significant delays in the transportation of consumables or components used in our operations or the commodities we produce, as a result of increases in fuel or labor costs, higher demand for logistics services, weather-related impacts (such as low water levels along shipping routes) or otherwise, could adversely affect our results of operations. Additionally, if transportation service providers fail to deliver consumables or components used in our operations to us or the commodities we produce to our customers in a timely manner or at all, such failure could adversely impact our ability to meet our production schedules, delay our projects and capital initiatives, negatively affect our customer relationships and have a material adverse effect on our financial position and results of operations.

Our debt and other financial commitments may limit our financial and operating flexibility.

At December 31, 2024, our total consolidated debt was $8.9 billion (see MD&A and Note 6) and our total consolidated cash and cash equivalents was $3.9 billion ($4.7 billion including restricted cash and cash equivalents associated with PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks as described in MD&A and Note 10). We also have various other financial commitments, including reclamation and environmental obligations, take-or-pay contracts and leases. Although we have been successful in servicing debt in the past, refinancing our bank facilities and issuing new debt securities in capital markets transactions at the parent and subsidiary levels, there can be no assurance that we can continue to do so. In addition, we may incur additional debt in future periods or reduce our holdings of cash and cash equivalents in connection with funding existing operations, capital expenditures, dividends, share or debt repurchases, or in pursuing other business opportunities. For further information, see the risk factors below relating to mine closure and reclamation regulations and the increasing scrutiny and evolving expectations from stakeholders and other third parties, including creditors, with respect to our environmental and social practices, performance and disclosures.

Our level of indebtedness, restricted cash and other financial commitments could have important consequences to our business, including the following:
•Limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate;
•Increasing our vulnerability to general adverse economic, financial, industry and regulatory conditions;
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•Limiting our ability to fund future working capital, capital expenditures, general corporate requirements and/or material contingencies, to engage in future development activities or other business opportunities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt;
•Requiring us to sell assets to reduce debt; or
•Placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments.

Any failure to comply with the financial and/or other covenants in our debt agreements may result in an event of default that would allow the creditors to accelerate maturities of the related debt, which in turn may trigger cross-acceleration or cross-default provisions in other debt agreements. Our available cash and liquidity may not be sufficient to fully repay borrowings under our debt instruments that may be accelerated upon an event of default.

As of January 31, 2025, our senior unsecured debt was rated “Baa2” with a stable outlook by Moody’s Investors Service, “BBB” with a stable outlook by Fitch Ratings, and “BBB-” with a stable outlook by Standard & Poor’s. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to these credit rating agencies, or should our business prospects deteriorate, our current credit ratings could be downgraded, which could adversely affect the value of our outstanding securities and existing debt, our ability to obtain new financing on favorable terms and could increase our borrowing costs.

Changes in or the failure to comply with the requirements of mine closure and reclamation regulations could have a material adverse effect on our business.

We are required by U.S. federal and state laws and regulations to provide financial assurance sufficient to allow a third party to implement approved closure and reclamation plans for our mining properties if we are unable to do so. As of December 31, 2024, our financial assurance obligations totaled $2.0 billion for closure and reclamation costs of U.S. mining sites. We are also subject to financial assurance requirements in connection with our remaining oil and gas properties and certain of our previously sold oil and gas properties under both state and federal laws. Refer to Note 10 for additional information regarding our financial assurance obligations and Items 1. and 2. “Business and Properties” for a discussion of certain of such U.S. federal and state laws and regulations applicable to us. A substantial portion of our financial assurance obligations are satisfied by guarantees by us and certain of our subsidiaries. Our ability to continue to provide guarantees depends on state and other regulatory requirements, our financial performance and our financial condition. Other forms of assurance, such as letters of credit and surety bonds, are costly to provide and, depending on our financial condition and market conditions, may be difficult or impossible to obtain. Failure to provide or maintain the required financial assurance could result in the closure of the affected properties.

Plans and provisions for mine closure, reclamation and remediation and oil and gas properties plugging and abandonment obligations may change over time as a result of changes in stakeholder and other third-party expectations, legislation, standards, and technical understanding and techniques, which may cause our actual costs of closure, reclamation and remediation and plugging and abandonment obligations to be higher than estimated for asset retirement obligations (AROs) and environmental obligations and could materially affect our financial position or results of operations. For example, our implementation of the Global Industry Standard for Tailings Management (the Tailings Standard) (refer to Items 1. and 2. “Business and Properties” for further discussion) has required changes and could require additional changes to our closure and reclamation plans or modifications to previously completed reclamation actions. In addition, climate change could lead to changes in the physical risks posed to our operations, which could result in changes in our closure and reclamation plans to address such risks. Any modifications to our closure and reclamation plans that may be required to address physical climate risks may increase our financial assurance obligations and may materially increase the actual costs associated with implementing closure and reclamation at any or all of our active or inactive mine sites or smelter sites. Refer to Notes 1 and 10 for further discussion of our environmental obligations and AROs and see the risk factors below relating to the potential physical impacts of climate change and our related obligations as part of our commitment to implementing the Tailings Standard.


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Unanticipated legal proceedings or negative developments in pending legal proceedings or other contingencies could have a material adverse effect on our financial condition.

We are, and may in the future become, involved in various legal proceedings and subject to other contingencies that have arisen or may arise in the ordinary course of our business or are associated with environmental matters, including those described in Note 10, Items 1. and 2. “Business and Properties” and in Item 3. “Legal Proceedings.” We are also involved periodically in other reviews, inquiries, investigations and proceedings initiated by or involving government agencies, some of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. For example, we have been cooperating with and responding to a subpoena from the U.S. Securities and Exchange Commission (SEC) and an information request from the Department of Justice related to our public disclosures about the engineering design and construction of the new smelter in Indonesia, which is also the subject matter in a separate whistleblower complaint from a former contractor that we are defending before the Department of Labor. We cannot predict the outcome of these investigations, and the outcome of any legal proceeding is inherently uncertain and adverse developments or outcomes can result in significant monetary damages, penalties, other sanctions or injunctive relief against us, limitations on our property rights, or regulatory interpretations that increase our operating costs, some of which may not be covered by insurance. Further, to the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Management does not believe, based on currently available information, that the outcome of any individual legal proceeding currently pending will have a material adverse effect on our financial condition, although individual or cumulative outcomes could be material to our operating results for a particular period, depending on the nature and magnitude of the outcome and the operating results for the period.

Regardless of the merit of particular claims, defending against legal proceedings or responding to investigations can be expensive, time-consuming, disruptive to our operations and distracting to management. In recognition of these considerations, we may enter into agreements or other arrangements to settle legal proceedings and resolve such challenges. There can be no assurance such agreements can be obtained on acceptable terms or that legal proceedings will not occur.

From time to time, we are involved in disputes over the allocation of environmental response costs and obligations at “Superfund” and other sites. We may be held responsible for the costs of addressing contamination at the site of current or former activities or at third-party sites or be held liable to third parties for exposure to hazardous substances should those be identified in the future. For further discussion of our environmental obligations, see the regulatory, environmental and social risks below.

Further, we are a global business with operations in various jurisdictions. In the event of a dispute arising at our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or arbitral panels, or may not be successful in subjecting foreign persons to the jurisdiction of courts or arbitral panels in the U.S. or in enforcing the judgment of a foreign court or arbitral panel against a sovereign nation. Our inability to enforce our rights and the enforcement of rights on a prejudicial basis by foreign courts or arbitral panels, including against a sovereign nation, could have an adverse effect on our results of operations and financial position.

Changes in tax laws and regulations could have a material adverse effect on our financial condition.

As a global business, we are subject to income, royalty, transaction and other taxes in the U.S. and various foreign jurisdictions. Uncertainties exist with respect to our tax liabilities, including those arising from changes in laws in the jurisdictions in which we do business. Additionally, we are subject to regular review and audit by both domestic and foreign tax authorities. Although we believe our tax estimates are reasonable, the ultimate tax outcome may differ from the tax amounts recorded in our financial statements and may materially affect our income tax provision, net income, or cash flows in the period or periods for which such determination and settlement occurs.

We have significant net operating losses (NOLs) in the U.S. generated in prior years. These NOLs are available to offset future regular taxable income, which we believe will result in minimal estimated regular income tax liability in the U.S. over the next several years at current metals market prices. As discussed in MD&A and Note 9, the provisions of the U.S. Inflation Reduction Act of 2022 (the Act) became applicable to us on January 1, 2023. The Act includes, among other provisions, a new Corporate Alternative Minimum Tax (CAMT) of 15% on the adjusted financial statement income (AFSI) of corporations with average annual AFSI exceeding $1.0 billion over a three-year period. In September 2024, the Internal Revenue Service (IRS) issued proposed regulations that provide guidance on the application of CAMT, which are not final and subject to change. Based on the proposed guidance
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released by the IRS, we have determined that the provisions of the Act did not impact our financial results for the years 2024 or 2023.

In December 2021, the Organisation for Economic Co-operation and Development (OECD) published a framework for Pillar Two of the Global Anti-Base Erosion Rules, which was designed to coordinate participating jurisdictions in updating the international tax system to ensure that large multinational companies pay a minimum level of income tax. Recommendations from the OECD regarding a global minimum income tax and other changes are being considered and/or implemented in jurisdictions where we operate. At current metals market prices, we do not expect enactment of the recommended framework in jurisdictions where we operate to materially impact our financial results.

International risks

Our operations are subject to evolving geopolitical, economic, regulatory and social risks.

We are a U.S.-based metals company with substantial assets located outside of the U.S. Risks of conducting business in the countries where we operate or do business, can include:
•Delays in obtaining or renewing, or the inability to obtain, maintain or renew, or the renegotiation, cancellation, revocation or forced modification (including the inherent risk of these actions being taken unilaterally by a foreign government or government owned entity) of contracts, leases, licenses, permits, easements, rights-of-way, stability agreements or other agreements and/or approvals;
•Expropriation or nationalization of property, protectionism, or restrictions on repatriation of earnings or capital;
•Changes in and differing interpretations of the host country’s laws, regulations and policies (which may be applied retroactively), including, but not limited to, those relating to labor, taxation, royalties, duties, tariffs, licenses, divestment, imports, exports (including restrictions on the export of copper concentrates and anode slimes, copper and/or gold), trade laws and regulations, immigration, currency, human rights and environmental matters (including land use and water use and, in some cases, consent), additional requirements on foreign operations and investment, and/or fines, fees and sanctions, criminal liability and other penalties imposed for failure to comply with the laws and regulations of the jurisdictions in which we operate, the risk of any of which may increase with rising “resource nationalism” in countries around the world;
•Geopolitical tensions, conflicts and events, social and economic instability, bribery, extortion, corruption, civil unrest, blockades, acts of war, guerrilla activities, insurrection and terrorism, certain of which may result in, among other things, an inability to access our property or transport our commodities;
•Risk of loss associated with illegal activity, including trespass, illegal mining, theft (including piracy), sabotage (including of critical infrastructure) and vandalism;
•Changes in U.S. trade, tariff and other controls on imports and exports, tax, immigration or other policies that may impact relations with foreign countries or result in retaliatory policies;
•Increases in training and other costs and challenges relating to requirements to employ nationals of a country in which a particular operation is located;
•Foreign exchange controls and fluctuations in foreign currency exchange rates; and
•Reduced protection for intellectual property rights.

Accordingly, our activities in the U.S. and outside of the U.S. may be substantially affected by many external factors beyond our control, any of which could have a material adverse effect on our cash flows, results of operations and financial condition.

We are required to comply with a wide range of laws and regulations in the countries where we operate or do business. For example, our international operations must comply with the U.S. Foreign Corrupt Practices Act (FCPA) and similar anti-corruption and anti-bribery laws of the other jurisdictions in which we operate. We are investigating whether activities of PT Smelting may have violated aspects of the FCPA or other laws, including laws of non-U.S. jurisdictions. PT Smelting is an Indonesian joint venture between PT-FI and Mitsubishi Materials Corporation (MMC). An affiliate of MMC serves as operator of PT Smelting (see Note 2). We have voluntarily
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notified the SEC and Department of Justice that we have engaged outside counsel to conduct this investigation of PT Smelting’s activities. Any determination that operations or activities are not in compliance with existing laws, including the FCPA, could result in the imposition of fines, penalties and equitable remedies. We cannot currently predict the outcome of the investigation.

We operate in jurisdictions that have experienced public and private sector corruption and where significant anti-corruption enforcement activities, prosecutions and settlements have occurred. We have a large number of contracts with local and foreign business partners, including suppliers and contractors, who may take action contrary to or fail to adopt standards, controls and procedures, including health, safety, environmental, human rights and community standards that are equivalent to our standards, controls and procedures. There can be no assurance that our policies, procedures and internal controls will protect us from misinterpretation of or noncompliance with applicable laws and internal policies, recklessness, fraudulent behavior, dishonesty or other inappropriate acts committed by our affiliates, employees, contractors or other business partners. As such, our policies, procedures and internal controls may not prevent or detect all potential breaches of law or governance practices. Any breaches could result in safety events that may result in injuries or fatalities; significant criminal or civil fines, penalties, litigation or regulatory action or inquiries or other enforcement actions; shareholder or other stakeholder activism (such as to stop using a certain business partner); civil unrest or other adverse impacts on human rights; termination of contracts; loss of operating licenses or permits; and damage to our reputation, any of which could have a material adverse effect on our cash flows, results of operations and financial condition.
In addition, our insurance does not cover most losses caused by the risks described above. For example, we do not have political risk insurance.

We conduct international operations and exploration activities in Indonesia, Peru and Chile as well as other foreign jurisdictions. Accordingly, in addition to the usual risks associated with conducting business in countries outside the U.S., our business may be adversely affected by political, economic, social and regional uncertainties in each of these countries. Other risks specific to certain countries in which we operate are discussed in more detail below.

Because our operations in Indonesia are material to our business, our business may be adversely affected by political, economic, regulatory and social uncertainties in Indonesia.

Maintaining a good working relationship with the Indonesia government, PT Mineral Industri Indonesia (Persero) (MIND ID), an Indonesia state-owned enterprise and shareholder in PT-FI, and the local population, is important because of the significance of our Indonesia operations to our business, and because our operations there are among Indonesia’s most significant business enterprises. Partially because of the Grasberg minerals district’s significance to Indonesia’s economy, the environmentally sensitive area where it is located, and the number of local people employed, our Indonesia operations have been the subject of political debates and criticism in the Indonesia press and have been the target of protests and occasional violence. Improper management of our working relationship with the Indonesia government, MIND ID or the local population could lead to a disruption of operations and/or impact our reputation in Indonesia and in the region where we operate, which could adversely affect our business.

The mining industry is subject to extensive regulation within Indonesia, and there have been major developments in laws and regulations applicable to mining concession holders, some of which have conflicted with PT-FI’s contractual rights and may conflict with PT-FI’s contractual rights in the future.

For example, in 2009, the Indonesia government enacted a mining law that sought to modify PT-FI’s former contract of work, certain provisions of which were not required under or conflicted with PT-FI’s former contract of work. In December 2018, PT-FI was granted an IUPK to replace its former contract of work, enabling PT-FI to conduct operations in the Grasberg minerals district through 2041, subject to certain requirements. Refer to Note 11 for a summary of the IUPK’s key fiscal terms and requirement to develop additional smelting and refining capacity. Pursuant to regulations issued during 2024, PT-FI is eligible to apply for an extension of its mining rights beyond 2041, provided certain conditions are met. Refer to Note 10 for a summary of such conditions. Application for extension may be submitted at any time up to one year prior to the expiration of PT-FI’s IUPK. PT-FI expects to apply for an extension during 2025, pending agreement with MIND ID on a purchase and sale agreement for the transfer in 2041 of an additional 10% interest in PT-FI. We cannot guarantee that PT-FI will receive an extension of mining rights beyond 2041.

Since 2019, the Indonesia government has enacted various laws and regulations related to downstream processing of various products. Refer to “Operations – Indonesia” in MD&A and Notes 10 and 11 for a discussion of Indonesia
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regulatory matters, including those related to export licenses, export duties, export proceeds, smelter assurance bonds and PT-FI’s new smelter and PMR (collectively, PT-FI’s new downstream processing facilities) in Eastern Java, Indonesia.

In October 2024, a fire occurred during commissioning of PT-FI’s new smelter in Eastern Java, Indonesia, requiring a temporary suspension of smelting operations to complete repairs. Procurement of long-lead items is advanced, and repairs are scheduled to be completed by mid-2025. Current regulations in Indonesia prohibit exports of copper concentrate as of January 1, 2025. Pursuant to the terms of its IUPK regarding force majeure events, PT-FI has requested approval from the Indonesia government to permit the export of copper concentrates in 2025 until the required repairs of its new smelter following the October 2024 fire incident and full ramp-up are complete. Based on discussions with the Indonesia government, PT-FI expects to re-commence exports of copper concentrate during first-quarter 2025, and pursuant to current regulations, would be required to pay a 7.5% export duty on all copper concentrate exports during 2025. If PT-FI does not receive a timely export license or if any limitations on exports or additional export duties resulting from Indonesia regulations were to be implemented prior to PT-FI’s new downstream processing facilities becoming operational, PT-FI could be required to reduce production levels or be subject to increased costs, which could adversely impact our revenues and operations.

There can be no assurance that future regulatory changes affecting the mining industry in Indonesia will not be introduced or unexpectedly repealed, or that new interpretations of existing laws and regulations will not be issued, any of which may conflict with PT-FI’s contractual rights, which could adversely affect our business, financial condition and results of operations.

Beginning in 2022, the Indonesia government divided the Indonesia portion of the island of New Guinea from two provinces into a total of six provinces, which has resulted in public protest and civil unrest. For further discussion of violence, civil and religious strife, and activism affecting our operations in Indonesia, see the related risk factor below. Further, we cannot predict the impact of splitting provinces on local and regional regulations, permits and other governmental administrative functions, which could have an adverse impact on our business.

In 2024, Indonesia held national legislative elections, including the presidential election. Political considerations and administrative changes resulting from these elections or future elections could affect, among other things, national and local policies pertaining to foreign investment, permitting and export restrictions, which could adversely affect our Indonesia operations.

In accordance with a regulation issued by the Indonesia government in 2023, 30% of PT-FI’s gross export proceeds are being temporarily deposited into Indonesia banks for a period of 90 days before withdrawal. The Indonesia government is considering changes to this regulation, which could increase the amount and length of the requirement, but also allow withdrawals from the balances to fund business requirements. The details of the modifications have not been finalized.

PT-FI will not mine all of the ore reserves in the Grasberg minerals district before the initial term of its IUPK expires in 2031. PT-FI’s IUPK may not be extended through 2041 if PT-FI fails to abide by its terms and conditions and applicable laws and regulations.

Under the terms of PT-FI’s IUPK, PT-FI has been granted mining rights through 2031, with rights to extend its mining rights through 2041, subject to certain terms and conditions. Refer to Note 11 for a summary of the IUPK’s key fiscal terms.

Our proven and probable mineral reserves in Indonesia reflect estimates of minerals that can be recovered through the end of 2041, and PT-FI’s current long-term mine plan and planned operations are based on the assumption that PT-FI will abide by the terms and conditions of the IUPK and will be granted the 10-year extension from 2031 through 2041. As a result, PT-FI will not mine all of these mineral reserves during the initial term of the IUPK. Prior to the end of 2031, we expect to mine 40% of aggregate proven and probable recoverable mineral reserves at December 31, 2024, representing 45% of FCX’s net equity share of recoverable copper reserves in Indonesia and 44% of FCX’s net equity share of recoverable gold reserves in Indonesia.

If PT-FI does not achieve full ramp-up at the new downstream processing facilities, or fulfill its defined fiscal obligations to the Indonesia government as set forth in the IUPK, the IUPK may not be extended from 2031 through 2041, and PT-FI would be unable to mine all of its proven and probable mineral reserves in the Grasberg minerals district, which could adversely affect our business, results of operations and financial position.
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PT-FI and the Indonesia government continue to engage in discussions regarding the extension of PT-FI’s IUPK beyond 2041. While PT-FI expects to apply for an extension during 2025, pending agreement with MIND ID on a purchase and sale agreement for the transfer in 2041 of an additional 10% interest in PT-FI, we cannot predict whether the application will be successful in extending PT-FI’s IUPK beyond 2041.

Operational risks

Our operations are subject to significant operational risks that could adversely affect our business, including the ability to smelt and refine, and our underground mining operations have higher risks than a surface mine.

We have assets in a variety of geographic locations, all of which exist in and around broader communities and environments. Maintaining the operational integrity and performance of our assets is crucial to protect our people, the environment and communities in which we operate. Our operations are very large in scale and, by their nature are subject to significant operational risks, some of which are outside of our control, and many of which are not covered fully, or in some cases even partially, by insurance. These operational risks, which could materially adversely affect our business, operating results and cash flows, include earthquakes, rainstorms, floods, landslides, wildfires and other natural disasters and extreme weather events; environmental hazards, including discharge of metals, concentrates, pollutants or hazardous chemicals; surface or underground fires; equipment failures; accidents, including in connection with mining equipment, milling equipment or conveyor systems, transportation of chemicals, explosives or other materials and in the transportation of employees and other individuals to and from sites (including where these services are provided by third parties such as vehicle and aircraft transport); wall failures and rock slides in our open-pit mines, and structural collapses of our underground mines or tailings impoundments; underground water and ore management; lower than expected ore grades or recovery rates; and seismic activity resulting from unexpected or difficult geological formations or conditions (whether in mineral or gaseous form).

For a discussion of risks specific to our tailings management, see the risk factors below relating to our management of waste rock and tailings, including our river transport system for tailings management in Indonesia.

We are facing continued geotechnical challenges because of the older age of some of our open-pit mines and a trend toward mining deeper pits and more complex deposits. There can be no assurance that unanticipated geotechnical and hydrological conditions may not occur, nor whether these conditions may lead to events such as landslides and pit wall failures, or that such events will be detected in advance. Geotechnical instabilities can be difficult to predict and are often affected by risks and hazards outside of our control, such as seismic activity or extreme weather, which have in the past and may in the future lead to floods, mudslides, pit-wall instability and possibly even slippage of material, which has and may in the future require suspension of operations and impact operating results.

We also experience mining induced seismic activity, including landslides, from time to time in the Grasberg minerals district in addition to extreme weather. The mine site is in an active seismic area and has experienced earth tremors from time to time. In addition to the usual risks encountered in the mining industry, our Indonesia mining operations involve additional risks given their location in steep mountainous terrain in a remote area of Indonesia. These conditions have required us to overcome special engineering difficulties and develop extensive infrastructure facilities. The area also receives extreme rainfall, which has led to periodic floods and mudslides. In February 2023, PT-FI’s operations were temporarily disrupted because of significant rainfall and landslides, which restricted access to infrastructure near its milling operations. We cannot predict whether similar weather-related or seismic events will occur in the future or the extent to which any such event would affect these, or any of our other operations.

Underground mining operations have unique risks that can be particularly dangerous, such as those associated with supporting the underground openings. In May 2013, the rock structure above the ceiling of an underground training facility at the Grasberg minerals district collapsed, which resulted in 28 fatalities and 10 injuries. While we have implemented preventative measures, we cannot guarantee that any incidents will not occur in the future.

The occurrence of one or more of these operational risks in connection with our operations may result in the death of, or personal injury or illness to, our employees, other personnel or third parties, the loss of mining equipment, damage to or destruction of mineral properties or production facilities, significant repair costs, monetary losses, deferral or unanticipated fluctuations in production, extensive community disruption (including short- and long-term health and safety risks), loss of licenses, permits or necessary approvals to operate, loss of workforce confidence,
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loss of infrastructure and services, disruption to essential supplies or delivery of our products, environmental damage and potential legal liabilities, any of which may adversely affect our reputation, business, prospects, results of operations and financial position. Further, the impacts of any serious incidents that occur may also be amplified if we fail to respond timely or in an appropriate manner.

In addition, we could also be subject to additional operational risks at our smelters and refineries, including those specific to PT-FI once it is fully dependent on its ability to smelt and refine domestically all its concentrates. Any delay, suspension, loss of access, shutdown of affected facilities or limited availability and capacity related to these smelting and refinery facilities, including equipment or mechanical failures, fires, explosions, unanticipated or extended shutdowns, inability to sell certain by-products, lack of capacity to store certain by-products, extreme weather or natural disasters, social or political unrest or any major public health crisis, any of which may not be recognized as a force majeure event, may significantly impact our ability to export and sell our products, particularly in Indonesia even if alternative refineries or smelters outside of Indonesia are available, and could adversely impact our costs, revenues and results of operations or require us to revise our operating plans, including curtailing or modifying our mining and milling operations. As discussed above and in Note 10, a fire occurred in October 2024 during start-up activities at PT-FI’s new smelter, requiring a temporary suspension of smelting operations to complete repairs. PT-FI expects repairs to be completed by mid-2025 and ramp-up to full capacity to be achieved by year-end 2025.

We maintain insurance at amounts we believe to be reasonable to cover some of these risks and hazards; however, our insurance may not sufficiently cover losses from certain of these risks and hazards. There can be no assurance that such insurance will continue to be maintained or available at economically feasible premiums, that the proceeds of such insurance will be paid in a timely manner or that we will be adequately compensated for losses actually incurred, if at all. We may elect not to purchase insurance for certain risks because of the high premium costs associated with insuring such risk or for various other reasons. For example, we do not have coverage for certain environmental losses, including the legal liabilities associated with these risks. The lack of, or insufficiency of, insurance coverage could adversely affect our cash flows and overall profitability.

Our management of waste rock and tailings are subject to significant environmental, safety and engineering challenges and risks that could adversely affect our business.

The waste rock (including overburden) and tailings produced in our mining operations represent our largest volume of mine waste material. Managing the volume of waste rock and tailings presents significant environmental, safety and engineering challenges and risks primarily relating to structural stability, geochemistry, water quality and dust generation. Management of this waste is regulated in the jurisdictions where we operate and our programs are designed to comply with applicable national, state and local laws, permits and approved environmental impact studies.

We maintain large leach pads and tailings impoundments containing viscous material. Our leaching innovation initiatives include measures that are intended to enhance solution flow through our leach stockpiles, which may increase risks for physical instability of such stockpiles. Tailings impoundments include large embankments that must be engineered, constructed and monitored to ensure structural stability and avoid structural collapse. Our tailings impoundments in arid areas must have effective programs to suppress fugitive dust emissions to meet regulatory requirements, which vary depending on location, and to limit potential impacts of dust emissions from our operations on surrounding communities and the environment. Additionally, we must effectively monitor, prevent and treat acid rock drainage at all of our operations. In Indonesia, we use a controlled riverine tailings management system, which presents other risks discussed in more detail in the risk factor below relating to the environmental challenges at our Indonesia mining operations.

As of December 31, 2024, we operated 15 active tailings storage facilities (13 in the U.S. and 2 in Peru), of which 10 have an upstream design and 5 have a centerline design. Additionally, we have one centerline tailing storage facility in development. We also manage 29 tailings storage facilities in the U.S. that are inactive or closed (23 with an upstream design, 2 with a centerline design and 4 with a downstream design) and another 25 that are deemed “safely closed” according to the definition in the Tailings Standard (22 with an upstream design and 3 with a centerline design). In 2024, we produced approximately 346 million metric tons of tailings globally. The failure of tailings storage facilities, other embankments or stockpiles at any of our mining operations could cause severe, and in some cases catastrophic, property and environmental damage and loss of life, as well as adverse effects on our business and reputation. Some of our tailings storage facilities are located in areas where a failure has the potential to impact individual dwellings, and at least one of our impoundments is in an area where a failure has the potential
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to impact nearby communities or mining infrastructure. There can be no assurance that a severe or catastrophic failure of any of our facilities will not occur in the future. For additional information regarding the company’s tailings management and stewardship program, including our implementation of the requirements of the Tailings Standard, refer to Items 1. and 2. “Business and Properties.”

Based on observations from tailings failures at unaffiliated mines and our risk assessment process, which assesses a range of potential risks to our tailings storage facilities, in addition to fatalities and severe personal, property and environmental damages, these events could result in limited or restricted access to mine sites, physical failures at sites (such as overtopping of an impoundment), suspension of operations, decrease in mineral reserves, legal liability, government investigations, additional regulations and restrictions on mining operations in response to any such failure, increased monitoring costs and production costs, increased insurance costs or costs associated with insufficiency of or inability to obtain insurance, increased costs and/or limited access to capital, remediation costs, inability to comply with any additional safety requirements or obtain necessary certifications, evacuation or relocation of communities or other emergency action, impacts on occupational health and safety, social risks, and other impacts, which could have a material adverse effect on our operations and financial position.

Our Indonesia mining operations are susceptible to difficult and costly environmental challenges, and future changes in Indonesia environmental laws could increase our costs.

Mining operations on the scale of our Indonesia operations involve significant environmental risks and challenges. Given the unique site-specific topographical, hydrological and geotechnical conditions of the project area, our primary challenge is to dispose of the large volume of tailings we produce. In 2024, PT-FI produced approximately 73 million metric tons of tailings. Our tailings management plan, which has been approved by the Indonesia government, uses an unnavigable part of a river in the highlands to transport the tailings and natural sediments from the mill in the highlands to an engineered tailings management area in the lowlands. Levees have been constructed along both sides of the lowlands tailings management area to act as containment structures to laterally contain the depositional footprint of the tailings and natural sediment within the approved tailings management area.

Another major environmental challenge at PT-FI is managing overburden stockpiles and other waste rock and conditions in the open pit. Overburden is rock that was previously moved aside in the Grasberg open pit mining process to reach the ore. In the presence of air, water and naturally occurring bacteria, some of this material can generate acid rock drainage (acidic water containing dissolved metals) that, if not properly managed, can adversely affect the environment or be costly to manage. There is no guarantee our actions to prevent and manage the quality of any discharge of impacted water will be successful. PT-FI may modify its re-sloping, erosion control and water management plans in the future, which could lead to material increases in costs.

In addition, in the past, certain Grasberg overburden stockpiles experienced erosion over time that caused mineralized overburden material to enter into the lowlands tailings management area. This erosion affected the volume as well as the physical and chemical characteristics of the sediment material deposited in the lowlands tailings management area, which, if not properly managed, could result in environmental impacts. The underlying overburden erosion and run-off are being managed and controlled through an extensive re-sloping and water management project which is ongoing, and PT-FI has not experienced similar erosion issues since 2018.

PT-FI maintains a tailings deposition management plan and environmental monitoring program which consider the presence of this potentially acid-forming overburden in the lowlands tailings management area. PT-FI has expanded the scope of its environmental monitoring program which assesses potential environmental and human health impacts from overburden and tailings. As part of the expanded scope, in 2022 and 2023, PT-FI assisted the Mimika local health authority (LHA) with broad-based community health surveys, which provided further data on an extensive range of community health issues. There were no impacts attributable to PT-FI’s operations (inclusive of tailings and overburden) that were determined to be a priority focus of the LHA following the results of these assessments. In response to the health survey results, PT-FI and the LHA have agreed to collaborate on public health challenges moving forward. During 2024, PT-FI continued its routine assessments of surface waters, groundwaters, sediments and soils, dust and terrestrial and aquatic tissues.

In the past, the Indonesia government, stakeholders and other third parties have raised questions with respect to PT-FI’s tailings management systems and plans. We continue to revisit studies for alternative tailings management options. Our Indonesia mining operations are remotely located in steep mountainous terrain and in an active seismic area, which also experiences extreme weather events. Independent environmental management expert audits have reaffirmed conclusions from previous studies that PT-FI’s controlled riverine tailings management
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system represents the best alternative for tailings management given the volume of tailings produced and the site-specific conditions of the area.

Overtopping or failure of any of the PT-FI tailings containment structures (levees or protection structures) induced by extreme weather events such as floods, a major seismic event or naturally occurring weak ground under the structures, are potential risks. The potential impacts from any such occurrence could vary significantly depending upon the specific location of the failure. Unanticipated structural failure of these structures in certain areas in the future could result in flooding of the nearby communities and related loss of lives and/or severe personal, property and environmental damages. Under certain conditions, a failure may necessitate evacuation or relocation of communities or other emergency action, financial assistance to the communities impacted, and remediation costs to repair and compensate for the social, cultural and economic impacts associated with such failure.

In addition, in the southern (estuary) portion of the approved tailings management area, mathematical modeling of certain sediment transport scenarios indicates that tailings have the potential to be deposited outside of the approved lateral levees in adjacent mangroves. PT-FI has proposed additional extensions to the existing levees to the Indonesia regulators and is further evaluating the potential benefits and impacts. Indonesia regulators have further proposed a different strategy involving efforts to increase sediment retention through various methods as well as increase beneficial use of tailings. If the additional retention efforts are not successful, or if the permitting for these proposed protection structures is not reconsidered, any such depositional impacts outside of our existing approved footprint could impact the environment and communities. Refer to Items 1. and 2. “Business and Properties” for further discussion of our environmental obligations in Indonesia.

Managing these environmental challenges at our Indonesia operations could result in reputational harm and increased costs that could be significant.
There can be no assurance that future environmental changes affecting the mining industry in Indonesia will not be introduced or unexpectedly altered or repealed, or that new interpretations of existing Indonesia environmental laws and regulations will not be issued, which could have a significant impact on PT-FI.

Violence, civil and religious strife, and activism could result in loss of life and disrupt our operations.

Indonesia

Indonesia has long faced separatist movements and civil and religious strife in a number of provinces. Several separatist groups have sought increased political independence for the province of Central Papua, where our Grasberg minerals district is located. In Central Papua, there have been attacks on civilians by separatists and conflicts between separatists and the Indonesia military and police. In addition, illegal miners have clashed with police who have attempted to move them away from our facilities. Social, economic and political instability in Central Papua could materially adversely affect us if it results in damage to our property or interruption of our Indonesia operations.

Shooting incidents have occurred within the PT-FI project area, including along the road leading to our mining and milling operations, which in some instances have involved fatalities or injuries to our employees, contractors, government security personnel and civilians. We incurred no fatalities or injuries relating to shootings within the PT-FI project area since April 2020, and we have had no shootings associated with the PT-FI project area since January 2021. In 2024, based on publicly available reports, we believe that there were more than 60 incidents of separatist violence, resulting in approximately 50 fatalities outside of the PT-FI project area at the Grasberg minerals district but within the province of Central Papua. In one such incident, which did not directly involve or target PT-FI’s operations or workforce, gunfire was exchanged between government security forces and separatists in an area adjacent to the PT-FI project area. Separatist security incidents, including shootings, attacks on civil infrastructure and arson, continue to occur in Central Papua and other areas near the PT-FI project area. PT-FI actively monitors security conditions and the occurrence of incidents both regionally and within the project and support areas.

The safety of our workforce is a critical concern, and PT-FI continues to work with the Indonesia government to enhance security and address security-related issues within the PT-FI project area and in nearby areas, including at PT-FI’s new downstream processing facilities. Although we have implemented measures and safeguards consistent with both international standards and our own internal standards relating to the use of force and respect for human rights, the implementation of these measures and safeguards does not guarantee that personnel, national police or other security forces will uphold these standards in every instance.
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We also expect to be exposed to security risks relating to loss and theft of refined precious metals at the PMR. Any such loss or theft could lead to financial loss or a failure to satisfy our customer commitments, which could have an adverse impact on our reputation and business.

We cannot predict whether additional incidents will occur that could result in loss of life, or disruption or suspension of PT-FI’s operations. If other disruptive incidents occur, they could adversely affect our results of operations and financial condition.

South America

South America countries have historically experienced periods of economic growth, as well as recession, periods of high inflation and general economic and political instability.

In Peru, political uncertainty has created instability in the regulatory environment. Beginning in December 2022 and continuing in 2023, heightened tensions, protests and social unrest emerged in Peru following a change in the country’s political leadership, which temporarily resulted in delays in the transport of supplies, products and people at our Cerro Verde mine. During first-quarter 2023, Cerro Verde also operated at reduced rates from time-to-time until it resumed normal operations in March 2023. Other mining operations in the region temporarily halted mining activities as a result of the civil unrest. While demonstrations and road blockages subsided in 2023, the political situation in Peru remains complex. In addition, the potential for civil unrest, including in relation to mining operations, and disruption of commerce and supply chains continues. Other operations in the region have encountered significant issues with trespassers, illegal miners and civil demonstrations that impact their current operations, expansion projects, logistical supply and product transport. Such protests have occasionally been accompanied by acts of violence and property damage and continue intermittently in the region.

In Chile, despite the overwhelming electoral approval of a proposal to rewrite the constitution in a 2020 referendum, the product of the constitutional assembly was rejected by a majority of voters in 2022 and 2023. The political environment remains polarized and political parties are preparing for presidential elections by the end of 2025.

We cannot predict whether similar or more significant incidents of civil unrest or political instability will occur in the future in Peru or Chile. Although such civil unrest has not significantly impacted our results, similar events in the future could cause our South America operations to be materially impacted, in which case, we may not be able to meet our production and sales targets.

U.S.

The occurrence of one or more unexpected events in the U.S., including civil unrest, domestic or foreign terrorism, and other acts of violence, could adversely affect our North America operations and financial performance.

Our operations, including future expansions or developments, depend on the availability of significant quantities of secure water supplies.

We recognize that access to clean, safe and reliable water supplies is vital to the health and livelihood of our host communities. Our operations require physical availability and secure legal rights to significant quantities of water, and the increasing pressure on water sources requires us to consider both current and future conditions in our approach. We aim to balance our operational water requirements with those of the local communities, environment and ecosystems. Most of our North America and South America operations are in areas where competition for water supplies is significant, and where climate change may lead to increasing scarcity of water sources in the future. Continuous production at our operations and any future expansions or developments are dependent on many factors, including our ability to maintain our water rights and claims, and the continuing physical availability of the water supplies. Current and long-term water risks include those that arise from our operations and events that we do not control (such as extreme weather and other physical risks associated with climate change). For further discussion of the potential physical impacts of climate change, see the related risk factor below.

As discussed in Item 3. “Legal Proceedings,” in Arizona, where our operations use both surface water and groundwater, we are a participant in an active adjudication in which Arizona courts have been attempting, for 50 years, to quantify and prioritize surface water claims for the Gila River watershed, one of the state’s largest river systems. If we are not able to satisfactorily resolve the issues being addressed in the adjudications, our water uses
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could be diminished or curtailed, and our operations and any future expansions at Morenci, Safford (including Lone Star) and Sierrita could be adversely affected unless we are able to acquire alternative water sources.

Water for our Cerro Verde operation in Peru comes from renewable sources through a series of storage reservoirs on the Rio Chili watershed that collects water primarily from seasonal precipitation and from wastewater collected from the city of Arequipa and treated at a wastewater treatment plant constructed by us. Weather patterns have contributed to ongoing drought conditions in the area and water shortages at our Cerro Verde operation are possible, which could impact our operations.

Water for our El Abra operation in Chile currently comes from the continued pumping of groundwater from the Salar de Ascotán aquifer. The agreement to pump from this aquifer is subject to continued monitoring through 2029 of the aquifer water levels and select flora species to ensure that environmentally sensitive areas are not impacted by our pumping, which if impacted could cause reductions in pumping to restore water levels and could have an adverse effect on production from El Abra. Our permit for pumping of groundwater will expire in 2029 and any renewal or provisional extension may be challenging. We are evaluating water infrastructure alternatives to provide options to extend existing operations and support a future expansion, while continuing to monitor Chile’s regulatory and fiscal matters, as well as trends in capital costs for similar projects. There can be no assurance that we will be able to execute such water infrastructure plans or obtain a new permit or provisional extension, which could have an adverse impact on our operations. For further discussion, see the risk factor above relating to the geopolitical, economic and social risks associated with our operations.

Although our operations currently have access to sufficient water sources to support current operational demands, as discussed above, the availability of additional supplies for potential future expansions or development will require additional investments and will take time to develop, if available. While we are taking actions to acquire additional back-up water supplies for current and future mining operations, such supplies may not be available at acceptable cost, or at all. As such, the loss of a water right or currently available water supply could force us to curtail operations or force premature closures, and the ability to obtain future water supplies could prevent future expansions or developments, thereby increasing and/or accelerating costs or foregoing profitable operations.

We typically have sufficient water for our Indonesia operations, but at times and for reasons out of our control, we may have too much or not enough. The PT-FI project area receives considerable rainfall that makes it susceptible to periodic floods and mudslides, the nature and magnitude of which cannot be predicted. Conversely, the area has experienced, and may in the future experience, certain extended periods without rainfall, which can impact water availability at the milling operations.

Our information and operational technology systems have been and in the future may be adversely affected by cybersecurity events, disruptions, damage, failure and risks associated with implementation and integration.

Our industry has become increasingly supported by and dependent on digital technologies. Our strategy of operating large, long-lived, geographically diverse assets has been increasingly dependent on our ability to become fully integrated and highly automated. Many of our business and operational processes are heavily dependent on traditional and emerging technology systems to conduct day-to-day operations, improve safety and efficiency, and lower costs.

As our dependence on information systems, including those of our third-party service providers and vendors, grows, we have become more vulnerable to an increasing threat of continually evolving cybersecurity risks. In recent years, cybersecurity events have increased in frequency and magnitude and the methods used to gain unauthorized access change frequently, making it increasingly difficult for us to prevent cybersecurity incidents or detect and remediate incidents in a timely and effective manner. Attacks have included and may include, but are not limited to, installation of malicious software, phishing, ransomware, social engineering tactics and credential attacks, insider threats, denial of service attacks, unauthorized access to data and other advanced and sophisticated cybersecurity breaches and threats, including those that increasingly target critical operational technologies and process control networks and those that are increasingly using AI and quantum computing. Such attacks may be perpetrated by a variety of bad actors, some of which may reside in jurisdictions where law enforcement measures to address such attacks are ineffective.

We have experienced targeted and non-targeted cybersecurity events in the past and may experience them in the future. In August 2023, we determined that we were subject to a cybersecurity incident that affected certain of our
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information systems. We performed an investigation of the incident and its associated impact and incurred costs to remediate, which were not material. We cannot guarantee that events of a similar nature, with potentially greater exposure, will not occur in the future.

Cybersecurity threats could subject us to manipulation or improper use of our systems and networks, production downtimes, loss of sales, communication interruption or other disruptions and delays to our operations or to the transportation of products or infrastructure utilized by our operations, unauthorized release of proprietary, commercially sensitive, confidential or otherwise protected information, a misappropriation or loss of funds, the corruption of data, significant health and safety consequences, physical destruction of assets, environmental damage, loss of intellectual property, fines, penalties, litigation, regulatory or governmental investigation, liability under or termination of our contracts with third parties, damage to our reputation or financial losses from remedial actions, any of which could have a material adverse effect on our cash flows, results of operations and financial condition, and which in addition could adversely impact the effectiveness of our internal control over financial reporting. We do not maintain cyber risk insurance, and the lack of insurance coverage could adversely affect our cash flows and overall profitability in the event of a cybersecurity incident that has a material adverse effect on our business.

While cybersecurity events have not had a material impact on us, we can provide no assurance that we will not experience any such impact or additional interruptions to our operations in the future. Given the unpredictability of the timing and the evolving nature and scope of information and operational technology system disruptions, the various procedures and controls we use to monitor and protect against cybersecurity threats and to mitigate potential risks arising from such threats have not been effective in some instances and may not be sufficient in preventing future cybersecurity incidents. Further, as cybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate vulnerabilities to cybersecurity threats.

We could also be adversely affected by system or network disruptions if new or upgraded information or operational technology systems are defective, not installed properly or not properly integrated into our operations. System modification failures could have a material adverse effect on our business, financial position and results of operations and could, if not successfully implemented, adversely impact the effectiveness of our internal control over financial reporting.

Further, we increasingly depend on our information technology infrastructure for electronic communications among our operations, personnel, customers and suppliers around the world, including as a result of remote working and flexible working arrangements. These information technology systems, some of which are managed by third parties that we do not control, may be susceptible to damage, disruptions or shutdowns because of failures during the process of upgrading or replacing software, databases or components thereof, cutover activities in our restructuring and simplification initiatives, power outages, hardware failures, telecommunication failures, human errors, catastrophic events or other problems. Refer to Item 1C. “Cybersecurity” for further information on our cybersecurity governance, risk management and strategy.

Failure to successfully implement or develop new technology systems and increased exposure to risks associated with the use of these systems may adversely affect our business.

Information and operational technology systems continue to evolve and, in order to remain competitive, we must implement new technologies in a timely, cost-effective and efficient manner. For example, we may develop and apply AI in decision support systems, material characterization, equipment reliability, mineral extraction and remote/autonomous operation. We may also pursue strategic alliances, partnership or licensing arrangements with other companies in areas where we believe collaboration can produce technological and industry advancement, which involves special risks that may negatively impact us or our reputation, may not achieve intended objectives, and may not perform as contemplated. We also are advancing a series of initiatives to incorporate new applications, technologies and data analytics to our leaching processes. For additional information on our leaching innovation initiatives, see MD&A. Our failure to successfully implement or develop new technologies, including AI, may adversely affect our competitiveness and, consequently, our results of operations. In addition, we utilize AI and other new technologies in our software, applications and technology platforms to enhance our capabilities in producing copper, improve business processes and respond to threats to our technology platforms. The use of AI may increase our exposure to cybersecurity risks and additional risks relating to the protection of data, including increased exposure of confidential or otherwise protected information to unauthorized recipients, which could result
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in liability under or termination of our contracts with third parties, misuse of our intellectual property or other unintended consequences, as discussed in more detail in the risk factor above.

Major public health crises may have an adverse impact on our business.

Pandemics, epidemics, widespread illness or other major public health crises could negatively impact the global economy and adversely affect our operations and business, including our ability to conduct business, demand for the commodities we produce and our profit margins. Actions taken by governmental authorities and third parties to contain and mitigate the risk of spread of any major public health crisis may negatively impact our business, including a disruption of or change to our operating plans. For example, in March 2020, we had to temporarily transition our Cerro Verde mine to care and maintenance status and adjust operations to prioritize critical activities in response to a decree issued by the Peru government relating to COVID-19.

Our business and results of operations could be adversely affected if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions or other restrictions, or if workplace entry and travel are restricted resulting in the delay of key personnel or external consultants accessing our sites. A major health crisis at any of our operating sites, and particularly at PT-FI’s remote operating site, could disrupt or change our operating plans, which may have a material adverse effect on our business and results of operations.

Human capital risks

Labor disputes or labor unrest could disrupt our operations.

Our business is dependent on maintaining good relations with our workforce. A significant portion of our global employee population is covered by collective labor agreements with varying durations and expiration dates. Refer to Items 1. and 2. “Business and Properties” for additional information regarding labor matters, and expiration dates of such agreements. As of December 31, 2024, approximately 28% of our global employee population was covered by collective labor agreements and none of our global employee population was covered by agreements that will expire during 2025.

Labor agreements are negotiated on a periodic basis and may not be renewed on reasonably satisfactory terms to us or at all. If we do not successfully negotiate new collective labor agreements with our union employees, we may incur prolonged strikes and other work stoppages at our mining operations, which could adversely affect our financial condition and results of operations. Additionally, if we enter into a new labor agreement with any union that significantly increases our labor costs relative to our competitors, our ability to compete may be materially adversely affected.

We have in the past and could in the future experience labor disruptions such as work stoppages, work slowdowns, union organizing campaigns, strikes, or lockouts that could adversely affect our operations. There were no strikes or lockouts at any of our operations for the three years ended December 31, 2024.

We cannot predict whether additional labor disruptions will occur. Significant reductions in productivity or protracted work stoppages at one or more of our operations could significantly reduce our production and sales volumes or disrupt operations, which could adversely affect our cash flows, results of operations and financial condition.

Our success depends on our ability to recruit, retain, develop and advance qualified personnel.

Our success is dependent on the contributions of our highly skilled and experienced workforce. Our business depends on our ability to recruit, retain, develop and advance a qualified, inclusive and diverse workforce at all levels, including sufficient personnel to develop, implement and operate new technologies. Our ability to recruit qualified personnel is affected by the available pool of candidates with the training and skills necessary to fill the vacant positions, the impact on the labor supply because of general economic conditions and our ability to offer competitive compensation and benefit packages. We continued to face challenges in 2024 with an increasingly competitive and tight labor market, specifically in North America. The tight labor market, hiring more contract workers, and increased competition from other employers in North America continue to represent strategic challenges that are increasing our costs, reducing efficiency, impacting production and our ability to further expand current mining rates and will impact the timing of future developments in North America. If we fail to recruit, retain, develop and advance qualified, inclusive and diverse personnel necessary for the efficient operation of our business
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or fail to maintain a safe environment, we could continue to face labor challenges, which may result in, but are not limited to, decreased profitability, further decreases to productivity and efficiency, ongoing safety performance challenges, and the further delay of current and potential development projects, any of which may have a material adverse effect on our performance. Refer to Items 1. and 2. “Business and Properties” for further discussion of our human capital management, including health and safety, and employee engagement, training and development.

Risks related to development projects and mineral reserves

Development projects are inherently risky and may require more capital and have lower economic returns than anticipated, and the development of our underground mines are also subject to other unique risks.

Mine development projects typically require a number of years and significant expenditures during the development phase before production is possible. There are many risks and uncertainties inherent in all development projects including, but not limited to, unexpected or difficult geological formations or conditions and environmental challenges, potential delays (including the ability and timeframe to obtain permits, or because of weather events, social or political unrest or any major public health crisis), cost overruns, availability of economic sources and reliable access to water, power and infrastructure, lower levels of production during ramp-up periods, shortages of materials or labor, construction defects, equipment breakdowns and injuries to persons and property, social acceptance and, in some cases, Indigenous and community consent for potential impacts, partner alignment and efficient and profitable operation of mature properties. Creating and maintaining an inventory of projects depends on many factors and although we devote significant time and resources to our project planning, approval and review processes, many of our development projects are highly complex and rely on factors that are outside of our control, which may cause the actual time and capital required to complete a development project and operating costs after completion to exceed our estimates, especially in periods of high inflation.

All of our copper and gold production in Indonesia comes from underground mining in the Grasberg minerals district. The development of our underground mines is subject to other unique risks including, but not limited to, underground fires or floods, ventilating harmful gases, fall-of-ground accidents, and seismic activity resulting from unexpected or difficult geological formations or conditions, which we experience from time to time in the Grasberg minerals district. While we anticipate taking all measures that we deem reasonable and prudent in connection with the development of our underground mines to safely manage production, there can be no assurance that these risks will not cause schedule delays, revised mine plans, injuries to persons and property, or increased capital costs, any of which may have a material adverse impact on our cash flows, results of operations and financial condition. Refer to Items 1. and 2. “Business and Properties” and MD&A for further discussion of PT-FI’s development of the Kucing Liar deposit in the Grasberg minerals district and our other development projects.

We may not be able to maintain or grow our mineral reserves.

Our existing mineral reserves will be depleted over time by production from our operations. Because our profits are primarily derived from our mining operations, our ability to replenish our mineral reserves is essential to our long-term success. Depleted mineral reserves can be replaced in several ways, including expanding known ore bodies, reducing operating costs that could extend the life of a mine by allowing us to cost-effectively process ore types that were previously considered uneconomic, investing in and advancing new technologies (such as our leaching innovation initiatives), locating new deposits or acquiring interests in mineral reserves from third parties.

Exploration is highly speculative in nature, involves many risks and uncertainties, requires substantial capital expenditures (which may differ significantly from those estimated) and, in some instances, advances in processing technology, and is frequently unsuccessful in discovering significant mineral resources since new, large, long-life deposits are increasingly scarce. Accordingly, our current or future exploration programs may not result in the discovery of additional deposits that can be produced profitably. Even if significant mineral resources are discovered, it will likely take many years from the initial phases of exploration until commencement of production, during which time the economic feasibility of production may change.

We may not be able to discover, enhance, develop or acquire mineral reserves in sufficient quantities to maintain or grow our current reserve levels, which could negatively affect our cash flows, results of operations and financial condition.


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Estimates of mineral reserves and mineral resources are uncertain and the volume and grade of ore actually recovered may vary from our estimates.

Our estimates of mineral reserves and mineral resources have been prepared in accordance with the disclosure requirements of Subpart 1300 of SEC Regulation S-K. There are numerous uncertainties inherent in mineral estimates. Such estimates are, to a large extent, based on assumed long-term prices for the commodities we produce, primarily copper, gold and molybdenum, and interpretations of geologic data obtained from drill holes and other exploration techniques, which may not necessarily be indicative of future results. Our mineral estimates are based on the latest available geological and geotechnical studies. We conduct ongoing studies of our ore bodies to evaluate economic values and to manage risk. We revise our mine plans and estimates of recoverable proven and probable mineral reserves as required in accordance with the latest available studies. Geological assumptions about our mineral resources that are valid at the time of estimation may change significantly when new information becomes available.

Estimates of mineral reserves, or the cost at which we anticipate the mineral reserves will be recovered, are based on assumptions, such as metal prices and other economic inputs. Changes to such assumptions may require revisions to mineral reserve estimates which could affect our asset carrying values and may also negatively impact our future financial condition and results. Until mineral reserves are actually mined and processed, the quantity of ore and grades must be considered as an estimate only.

In addition, if the market prices for the commodities we produce decline from assumed levels, if production costs increase or recovery rates decrease, or if applicable laws and regulations are adversely changed, there can be no assurance that the indicated level of recovery will be realized or that mineral reserves can be mined or processed profitably. If we determine that certain of our estimated recoverable proven and probable mineral reserves have become uneconomic, this may ultimately lead to a reduction in our aggregate reported mineral reserves, which could have a material adverse effect on our business, financial condition and results of operations.

Additionally, the term “mineral resources” does not indicate recoverable proven and probable mineral reserves as defined by the SEC. Estimates of mineral resources are subject to further exploration and evaluation of development and operating costs, grades, recoveries and other material factors, and, therefore, are subject to considerable uncertainty. Mineral resources do not meet the threshold for mineral reserve modifying factors, such as engineering, legal and/or economic feasibility, that would allow for the conversion to mineral reserves. Accordingly, there can be no assurance that the estimated mineral resources not included in mineral reserves will become recoverable proven and probable mineral reserves.

Regulatory, environmental and social risks

The costs of compliance with environmental, health and safety laws and regulations applicable to our operations may constrain existing operations or expansion opportunities. Related permit and other approval requirements may delay or result in a suspension of our operations.

Our operations are subject to extensive and complex environmental laws and regulations governing the generation, storage, treatment, transportation and disposal of hazardous substances; solid waste disposal; air emissions; wastewater discharges; remediation, restoration and reclamation of environmental contamination, including mine closures and reclamation; protection of endangered and threatened species and designation of critical habitats; and other related matters. These laws and regulations are subject to change and to changing interpretation by governmental agencies and other bodies vested with broad supervisory authority. As a mining company, compliance with environmental, health and safety laws and regulations is an integral and costly part of our business. In addition, we must obtain regulatory permits and other approvals to start, continue and expand operations, which could be challenged causing delays or possible denial of necessary permits and other approvals.

Certain federal and similar state laws and regulations may expose us to joint and several liability for environmental damages caused by our operations, or by previous owners or operators of properties we acquired or are currently operating or at sites where we previously sent materials for processing, recycling or disposal. As discussed in more detail in the risk factor below relating to costs incurred for remediating environmental conditions on our properties that are no longer in operation, we have substantial obligations for environmental remediation on properties previously owned or operated by Freeport Minerals Corporation (FMC) and certain of its affiliates. Noncompliance with these laws and regulations could result in material penalties or other liabilities. In addition, compliance with these laws may from time to time result in delays in or changes to our development or expansion plans. Compliance
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with these laws and regulations imposes substantial costs, which we expect will continue to increase over time because of increased regulatory oversight, adoption of increasingly stringent environmental standards, and other factors.

New or revised environmental regulatory requirements are frequently proposed, many of which have resulted and may in the future result in substantially increased costs for our business, including those regarding financial obligations. Regulations have been considered at various governmental levels to increase financial responsibility requirements for mine closure and reclamation. Adoption of such environmental regulations or more stringent application of existing regulations may materially increase our costs, threaten certain operating activities and constrain our expansion opportunities. In addition, there can be no assurance that restrictions relating to conservation will not have an adverse impact on expansion of our operations or not result in delays in project development, or constraints on exploration or operations in impacted areas.

We have incurred and expect to incur environmental capital expenditures and other environmental costs (including our joint venture partners’ shares) to comply with applicable environmental laws and regulations that affect our operations. The timing and amounts of estimated payments could change as a result of changes in regulatory requirements, changes in scope and costs of reclamation activities, the settlement of environmental matters and the rate at which actual spending occurs on continuing matters. For example, revised federal regulations governing hazardous air pollutant emissions at our Miami, Arizona smelter were finalized in May 2024 and are under evaluation.

We are also subject to extensive regulation of worker health and safety. Our mines are inspected on a regular basis by government regulators who may issue citations and orders when they believe a violation has occurred under applicable mining regulations. If inspections result in an alleged violation, we may be subject to fines and penalties and, in instances of alleged significant violations, our mining operations or industrial facilities could be subject to temporary or extended closures.

Many other governmental bodies regulate other aspects of our operations, and our failure to comply with these legal requirements can result in substantial penalties. In addition, new laws and regulations, including executive orders, or changes to or new interpretations of existing laws and regulations by courts or regulatory authorities occur regularly, but are difficult to predict. For instance, the U.S. Supreme Court’s 2024 decision in Loper Bright Enterprises v. Raimondo (Loper Bright) overruled Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc. (Chevron). Since 1984, Chevron had required courts to give judicial deference to administrative agency actions and reasonable agency interpretations where a statute was silent or ambiguous. In Loper Bright, the Supreme Court held that the U.S. Administrative Procedure Act requires courts to exercise independent judgment when deciding whether an agency acted within its statutory authority and that courts may not defer to agency interpretations solely because a statute is ambiguous. This decision may result in additional legal challenges to regulations and guidance issued by federal regulatory agencies, including those that impact our industry. Changes under a new president, administration and Congress in the U.S. are also difficult to predict. Any such variations could negatively impact the mining sector, including our business, substantially increase costs to achieve compliance or otherwise have a material adverse effect on our cash flows, results of operations and financial condition.

For additional information regarding the various regulations affecting us, see Items 1. and 2. “Business and Properties.”

We incur significant costs for remediating environmental conditions on or related to properties that have not been operated in many years.

FMC and its subsidiaries, and many of their affiliates and predecessor companies, have been involved in exploration, mining, milling, smelting and manufacturing in the U.S. for more than a century. Activities that occurred in the late 19th century and the 20th century prior to the advent of modern environmental laws generally were not subject to environmental regulation and were conducted before U.S. industrial companies fully understood the long-term effects of their operations on the surrounding environment.

Companies like FMC are now legally responsible for remediating hazardous substances released into the environment on or from properties owned or operated by them as well as properties where they arranged for disposal of such substances, irrespective of when the release into the environment occurred or who caused it. That liability is often asserted on a joint and several basis with other prior and subsequent owners, operators and arrangers, meaning that each owner or operator of the property is, and each arranger may be, held fully responsible
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for the remediation, although in many cases some or all of the other responsible parties no longer exist, do not have the financial ability to respond or cannot be found. As a result, because of our acquisition of FMC, many of the subsidiary companies we now own are potentially responsible for a wide variety of environmental remediation projects throughout the U.S., and we expect to spend substantial sums annually for many years to address those remediation issues. We are also subject to claims where the release of hazardous substances is alleged to have resulted in injury, destruction or loss of natural resources.
At December 31, 2024, we had more than 80 active remediation projects in 20 U.S. states. In addition, FMC and certain affiliates and predecessor companies were parties to agreements relating to the transfer of businesses or properties that contained indemnification provisions relating to environmental matters, and from time to time these provisions become the source of claims against us.

Our environmental obligation estimates are primarily based upon our current knowledge and understanding of:
•Complex scientific and historical facts and circumstances that in many cases occurred many decades ago;
•Assumptions regarding the nature, extent and duration of remediation activities that we will be required to undertake and the estimated costs of those remediation activities, which are subject to varying interpretations; and
•Interpretation of the requirements that are imposed on us by existing laws and regulations and, in some cases, the clarification of uncertain regulatory requirements that could materially affect our environmental obligation estimates.

Significant adjustments to these estimates are likely to occur in the future as additional information becomes available. The actual environmental costs may exceed our current and future accruals for these costs, and any such changes could be material.

In addition, remediation standards imposed by the U.S. Environmental Protection Agency (EPA) and state environmental agencies have generally become more stringent over time and may become even more stringent in the future. Imposition of more stringent remediation standards, particularly for arsenic and lead in soils, poses a risk that additional remediation work could be required at our active remediation sites and at sites that we have already remediated to the satisfaction of the responsible governmental agencies, and may increase the risk of toxic tort litigation. In January 2024, the EPA released guidance lowering the recommended screening levels for investigating lead-contaminated soils and in January 2025, EPA published its final toxicological assessment for inorganic arsenic. This guidance and assessment can be used to establish cleanup levels by some agencies at state and federal remediation sites and may lead to additional regulatory guidance, rulemaking and other regulatory activities. More stringent cleanup levels often lead to higher costs through exponential volume increases due to resulting expanded project footprints.

Refer to Items 1. and 2. “Business and Properties” and Note 10 for further discussion of our environmental obligations.

We face increasing, complex and changing regulatory and stakeholder and other third-party expectations relating to our climate and energy transition plans, which may adversely affect our business. Further, we may not be able to timely or successfully transition from fossil fuel sources for our significant energy needs, which may result in reputational damage.

Our operations require significant energy, much of which is currently from fossil fuel sources and is obtained from third parties under long-term contracts. Energy represented 16% of our copper mine site operating costs in 2024, and based on currently available information and projected operations, is expected to approximate 16% in 2025. The principal sources of energy consumption at our mining operations are: diesel fuel, which powers mine trucks and other transportation equipment; purchased electricity, which powers core facilities and certain on-site metal processing operations; and coal and natural gas, which provide electricity at certain operations.

Existing and proposed governmental conventions, laws, rules, regulations, policies and standards as well as existing and proposed voluntary disclosure standards and frameworks (both in the U.S. and internationally), including those related to climate change, carbon taxes, carbon markets or greenhouse gas (GHG) emissions, may in the future add significantly to our operating costs, limit or modify our operations, impact the competitiveness of the commodities we produce, and require more resources to comply and remediate in response. For additional
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information on climate change conventions, laws, regulations and standards applicable or that may in the future be applicable to FCX or its subsidiaries, refer to Items 1. and 2. “Business and Properties.”

In response to climate change and societal or stakeholder demands for action, we are advancing 2030 GHG emissions reduction targets and a 2050 net zero aspiration, each of which will result in additional costs to us, the totality of which we cannot currently estimate with accuracy, and we cannot guarantee that we will be able to achieve any current or future GHG emissions targets or aspirations.

While we strive to transition to more renewable power sources for our mining operations, as a commercial consumer of power, our ability to reduce our GHG emissions associated with our power consumption demand is largely dependent upon the mix of our suppliers and locally available renewable energy resources at our various sites, including our ability to successfully develop renewable energy projects and negotiate power purchase agreements. The transition to renewable and other energy sources could, among other things, increase our capital expenditures, and operating and energy costs, depending on the scope, magnitude and timing of increased regulation of fossil-fuel based energy production, including GHG emissions, as well as the availability of alternative energy sources.

In certain aspects of our operations, our ability to reduce our GHG emissions is directly dependent on the actions of third parties and technological solutions and innovation, and our ability to make significant, rapid changes in our GHG emissions in response to potential future regulations may be limited. For example, our diesel-fueled haul trucks are a significant contributor to GHG emissions at our North America and South America operations. We are evaluating options for the electrification of our haul trucks, but reduction of emissions from such haul trucks will depend upon the development and availability of commercially viable alternative-fueled mining equipment by our third-party suppliers. At our remote mining operations in Indonesia, PT-FI owns and operates a coal-fired power plant and continues to advance plans to transition its existing energy source from coal to natural gas. Once complete, PT-FI’s dual-fuel power plant and the new gas-fired combined cycle facility will be fueled by natural gas, supplied by a floating liquefied natural gas storage and regassification unit. Our ability to transition to commercially viable alternative sources of energy across our operations globally will depend on, among other things, additional studies, technological considerations, or permit or other approvals. Even if we do implement new technologies, our stakeholders and other third parties may not be satisfied with our approach to reducing our GHG emissions. For further information, see the risk factor below relating to the increasing scrutiny and evolving expectations from stakeholders and other third parties, including creditors, with respect to our environmental and social practices, performance and disclosures.

The physical impacts of climate change may adversely affect our mining operations, workforce, communities, biodiversity and ecosystems, supply chains and customers, which may result in increased costs.

We recognize that as the climate changes, our operations, workforce, communities, biodiversity and ecosystems, supply chains and customers may be exposed to changes in the frequency, intensity and/or duration of intense storms, drought, flooding (including from sea level rise at our coastal operations), wildfire, and other extreme weather events and patterns (such as extreme heat). For example, we experienced severe flooding, debris flow from heavy rain and landslides in early 2023 at our remote mining operations in Indonesia, which temporarily halted mining and processing work and damaged infrastructure near the milling complex. Such potential physical impacts of climate change on our operations are highly uncertain and would vary by operation based on particular geographic circumstances. For example, at many of our mine sites, climate change is projected to impact local precipitation regimes, resulting in shorter-duration, higher-intensity storm events, and the potential for less precipitation overall. We could face increased operational costs associated with managing additional volumes of storm water during more intense future events, including supply disruption, delays, damage to or inaccessibility of our facilities and increased pricing of consumables and components we purchase. In addition, the potential for overall decreases in precipitation could affect the availability of water needed for our operations, leading to increased operating costs, or in extreme cases, disruptions to our mining operations. For additional information regarding risks relating to availability of water and operational risks inherent in mining, see related risk factors above.
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Increasing scrutiny, action and evolving expectations from stakeholders and other third parties with respect to our ESG practices, performance, commitments and disclosures may impact our reputation, increase our costs and impact our access to capital or business strategy.

Stakeholder and other third-party scrutiny related to our ESG practices, commitments, performance and disclosures continues to increase and evolve. We have adopted certain policies and programs, including with respect to responsible production frameworks, climate change, water stewardship, biodiversity and land management, tailings management and stewardship, waste management (including of hazardous materials), safety and health, human capital management, human rights, social performance and community and Indigenous Peoples relations, political activity and spending practices, and supply chains/responsible sourcing. It is possible, however, that our stakeholders and other third parties might not be satisfied or even disagree with our ESG practices, goals, initiatives, commitments, performance and/or disclosures, or the speed of their adoption, implementation and measurable success. If we do not meet our stakeholders’ and other third parties’ evolving expectations, including any failure or perceived failure to achieve our stated goals and targets or industry standards or any allegations that our stated goals or targets should be altered, our reputation, competitiveness, access to and cost of capital, business strategy and stock price could be negatively impacted, and legal or regulatory proceedings could be brought against us.

Certain investor advocacy groups, institutional investors, investment funds, creditors and other influential investors are focused on our ESG practices and place importance on the ESG implications of their investments and lending decisions. Our ability to attract capital could be adversely impacted if they incorporate more stringent ESG considerations as a part of their portfolios.

Organizations that provide information to investors and financial institutions on ESG performance and related matters have developed quantitative and qualitative data collection processes and ratings processes for evaluating companies on their approach to these matters. Such ratings are used by some investors to inform their investment and voting decisions. In addition, many investors have created their own proprietary ratings that inform their investment and voting decisions. Unfavorable ratings or assessment of our ESG practices, including our compliance with certain voluntary disclosure standards and frameworks, may lead to negative investor sentiment toward us, which could have a negative impact on our stock price and our access to and cost of capital.

Similarly, many financial institutions are increasingly incorporating ESG ratings or assessments into their credit risk assessments, and screen companies based on their ESG practices and performance when making lending decisions. If we are unable to meet the ESG lending criteria set by our creditors or are required to take certain remediation steps to satisfy such criteria, our access to capital on terms we find favorable may be limited and our costs may increase.

Our public disclosures may reflect goals, aspirations, commitments, cost estimates and other expectations and assumptions, including over long timeframes, which are necessarily uncertain and may not be realized. Further, the voluntary disclosure standards or frameworks we choose to align with are evolving and may change over time and our interpretation of such disclosure standards and frameworks may differ from those of others, either of which may result in a lack of consistent or meaningful comparative data from period to period and/or significant revisions to our goals and aspirations or reported progress in achieving such goals and aspirations.

Ensuring that there are adequate systems and processes in place to comply with the various ESG tracking and disclosure obligations, or to respond to business partners or other affiliates in our value chain that have requested, or may in the future request, ESG-related data or information from us to meet their disclosure obligations, will require management’s time and expense. If we do not adapt to or comply with stakeholder or other third parties’ expectations, including with respect to evolving ESG disclosure standards and frameworks, or if we are perceived to have not responded appropriately, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business, financial condition, cost of capital and/or stock price could be materially adversely affected.

In addition, our customers, end users and other third parties may require that we implement certain additional ESG procedures or standards before they will start or continue to do business with us, which could lead to preferential buying based on our ESG practices compared to our competitors’ ESG practices. Further, being associated with activities by business partners or other affiliates that have or are perceived to have individual or cumulative adverse impacts on the environment, climate, biodiversity, nature and land management, water access and management, human rights or cultural heritage could negatively affect our reputation and impose additional costs.
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Failure or the perceived failure to manage our relationships with the communities and/or Indigenous Peoples where we operate or that are near our operations could harm our reputation and social license to operate.

Our relationships with the communities and/or Indigenous Peoples where we operate or that are adjacent to or near our operations are critical to the long-term success of our existing operations and the development of any future projects. There is ongoing and increasing stakeholder and other third-party concern relating to a company’s social license to operate and the actual, potential and perceived effects of mining activities on the environment and on communities impacted by such activities. We may engage in activities, such as exploration, production, construction or expansion of our operations that have or are perceived to have adverse impacts on the local communities and their relevant stakeholders, society as a whole, Indigenous Peoples, cultural heritage, human rights and the environment, including land management and associated biodiversity, among other things. For example, our operations may take place on or adjacent to Indigenous Peoples’ ancestral lands, and such Indigenous Peoples may assert rights to such lands. Further, we may be required or expected by our stakeholders and other third parties to consult with and/or obtain consent from Indigenous Peoples for potential impacts. We also may be required to demonstrate our capacity to protect ecosystems through improved practices and technological solutions to maintain our social license to operate, or to obtain such social license to operate for future development projects or expansions.

In addition, our assets are generally long-lived and stakeholders’ perceptions and expectations can change over the life of the mine. Changes in the aspirations and expectations of local communities and/or Indigenous Peoples where we operate, with respect to our employee health and safety performance and our contributions to infrastructure, community development, environmental management, including land management and associated biodiversity, and other factors could affect our social license to operate and reputation, and could lead to delays and/or increased costs if expansions or new projects are blocked either temporarily or for extended periods. Failure to effectively engage with communities on an ongoing basis, including the withdrawal of consent or support of Indigenous Peoples, other stakeholders or other third parties, could adversely impact our business, damage our reputation and/or result in loss of rights to explore, operate or develop our projects.

Risks related to our common stock

Our holding company structure may impact our ability to service our debt, declare dividends, and repurchase shares and debt.

We are a holding company with no material assets other than the capital stock and intercompany receivables of our subsidiaries. As a result, our ability to service our indebtedness, pay dividends, and repurchase shares and debt is dependent on the generation of cash flows by our subsidiaries and their ability to make such cash available to us, by dividend, loan, debt repayment or otherwise. Our subsidiaries do not have any obligation to make funds available to us to service our indebtedness, pay dividends, or repurchase shares and debt. Dividends from subsidiaries that are not wholly owned are shared with other equity owners. Cash at our international operations is also typically subject to foreign withholding taxes upon repatriation into the U.S.

In addition, our subsidiaries may not be able to, or be permitted to, make distributions to us or repay loans to us, to enable us to service our indebtedness, pay dividends, or repurchase shares and debt. Each of our subsidiaries is a distinct legal entity and, under certain circumstances, legal restrictions, as well as the financial condition and operating requirements of our subsidiaries, may limit our ability to obtain cash from our subsidiaries. Certain of our subsidiaries are parties to credit agreements that restrict their ability to make distributions or loan repayments to us if such subsidiary is in default under such agreements, or to transfer substantially all of the assets of such subsidiary without the consent of the lenders. Further, PT-FI has certain amounts of restricted cash and cash equivalents associated with its export proceeds that are required to be temporarily deposited in Indonesia banks, as described in MD&A and Note 10, which regulations may be revised including to increase the amount deposited and duration held. Our rights to participate in any distribution of our subsidiaries’ assets upon their liquidation, reorganization or insolvency would generally be subject to the prior claims of the subsidiaries’ creditors, including any trade creditors.

As more fully described in Note 8, during 2021, our Board of Directors (Board) adopted a performance-based payout framework, which currently includes base and variable dividends and a share repurchase program. Our ability to continue to pay dividends (base or variable) and the timing and amount of any share repurchases is at the discretion of our Board and management, respectively, and is subject to a number of factors, including not exceeding our net debt target, capital availability, our financial results, cash requirements, global economic
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conditions, changes in laws, contractual restrictions and other factors deemed relevant by our Board or management, as applicable. Repurchases of our common stock under our repurchase program are discretionary up to the Board-approved limit, and our share repurchase program may be modified, increased, suspended or terminated at any time at the Board’s discretion. Our dividend payments and share repurchases may change, and there can be no assurance that we will continue to declare dividends or repurchase shares at all or in any particular amounts. A reduction or suspension in our dividend payments or share repurchases could have a negative effect on the price of our common stock.

Anti-takeover provisions in our charter documents and Delaware law may make an acquisition of us more difficult.

Anti-takeover provisions in our charter documents and Delaware law may make an acquisition of us more difficult. These provisions may discourage potential takeover attempts, discourage bids for our common stock at a premium over market price or adversely affect the market price of, and the voting and other rights of the holders of, our common stock. These provisions could also discourage proxy contests and make it more difficult for stockholders to elect directors other than the candidates nominated by the Board. Refer to Exhibit 4.1 for further discussion of our anti-takeover provisions.

Further, our By-Laws provide to the fullest extent permitted by law that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have, or declines to accept, jurisdiction, the U.S. District Court for the District of Delaware) will be the sole and exclusive forum for any (i) derivative action or proceeding brought on our behalf, (ii) action asserting a claim that is based upon a violation of a duty by any of our current or former directors, officers, employees or stockholders in such capacity, (iii) action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (DGCL) or to which the DGCL confers jurisdiction upon the Court of Chancery of the State of Delaware, (iv) action asserting a claim governed by the internal affairs doctrine, or (v) action asserting an “internal corporate claim” as that term is defined in Section 115 of the DGCL. The exclusive forum provision may increase costs to bring a claim, discourage claims or limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us or our directors, officers and other employees. Alternatively, if a court were to find the exclusive forum provision contained in our By-Laws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions. The exclusive forum provision in our By-Laws will not preclude or contract the scope of exclusive federal or concurrent jurisdiction for actions brought under the federal securities laws including the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended, or the respective rules and regulations promulgated thereunder.

In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL, which may prohibit large stockholders from consummating a merger with, or acquisition of, us.

These provisions may deter an acquisition of us that might otherwise be attractive to our stockholders.

Item 1B.  Unresolved Staff Comments.

Not applicable.

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Item 1C.  Cybersecurity.

Risk Management and Strategy

We maintain a cyber risk management program designed to assess, identify, manage, mitigate and respond to cybersecurity threats and incidents. We seek to address material risks from cybersecurity threats through a cross-functional approach, and we utilize various processes to inform our identification, assessment and management of material risks from cybersecurity threats. Our cyber risk management program is integrated into our overall enterprise risk management (ERM) program. Cybersecurity risks are identified and assessed through our ERM program, which is designed to provide cross-functional executive insight across the business to identify and monitor risks, opportunities and emerging trends that can impact our strategic business objectives. The underlying controls of our cyber risk management program are based on recognized best practices and standards for cybersecurity and information technology, including the National Institute of Standards and Technology Cybersecurity Framework.

We utilize dedicated internal and external cybersecurity personnel to focus on assessing, detecting, identifying, managing, preventing and responding to cybersecurity threats and incidents. Our approach to cybersecurity incorporates a layered portfolio of technology controls, including strategic partnerships for our cybersecurity platforms, documented policies and procedures, periodic end user training, including cybersecurity awareness training for employees and certain contractors, and dedicated resources to manage and monitor the evolving threat landscape, including through the gathering of actionable threat intelligence. We maintain and periodically evaluate and, as needed, update our information security policy and an incident response plan, which describes the processes we use to prepare for, detect, respond to and recover from a cybersecurity incident, including processes to assess severity, escalate, contain, investigate and remediate an incident, as well as to comply with potentially applicable legal and disclosure obligations.

We regularly evaluate and assess the threat landscape and our security controls, including through audits and assessments, regular network and endpoint monitoring, vulnerability testing, penetration testing and tabletop exercises that include senior management. To assess the design and effectiveness of our cybersecurity controls, we engage with assessors, consultants, auditors and other third parties, including through independent third-party reviews of our information technology security program conducted on at least an annual basis. We also have processes to oversee and identify material cybersecurity risks associated with our use of third-party service providers, including utilizing safeguards to protect sensitive data, performing diligence on certain third parties that have access to our systems, data or facilities that store such systems or data, continually monitoring cybersecurity threat risks identified through such diligence and contracting to manage cybersecurity risks in specified ways such as requiring agreements to be subject to periodic cybersecurity audits.

We have experienced targeted and non-targeted cybersecurity incidents in the past, including an incident in August 2023 that affected certain of our information systems and resulted in temporary disruptions to parts of our operations. However, prior cybersecurity incidents, including the August 2023 incident, have not materially affected us. Notwithstanding our cyber risk management program, we may not be successful in preventing or mitigating a cybersecurity incident that could materially affect us, including our business strategy, results of operations or financial condition. Refer to Item 1A. “Risk Factors” for further information on the risks we face from cybersecurity threats.

Governance

Our Senior Vice President and Chief Innovation Officer, who has served in various senior leadership roles in operational improvement and technology during his nearly 30-year tenure with us, leads our innovation and technology initiatives, corporate information systems and financial shared services. Our cybersecurity risk management and strategy processes described in “Risk Management and Strategy” above are led by our Chief Information Officer (CIO) and our Chief Information Security Officer (CISO). Our CIO and CISO each report to our Chief Innovation Officer. Our CIO is responsible for the strategy, deployment, operational effectiveness and risk management of our technology systems and operations. Our CIO has over 30 years of experience in technology, cybersecurity and risk management, including leading information and technology initiatives for companies in the mining and energy sectors as a partner and senior managing director at a global professional services public company specializing in information technology services and management consulting. Our CISO is responsible for protecting our global technology systems from cybersecurity incidents, which includes overseeing the deployment of cybersecurity controls, managing a team of cybersecurity professionals and reporting on cybersecurity matters to management and the Audit Committee of our Board. Our CISO has 30 years of experience in the technology and
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cybersecurity industries, including 15 years serving as CISO for public companies. Our CISO is also a Certified Information Systems Security Professional.

Our ERM management committee is responsible for providing input and oversight on our ERM program, including cybersecurity risks. Our ERM management committee is comprised of senior leaders, including our Chief Innovation Officer, with responsibility across operations and core business functions, and with a breadth of knowledge, influence and experience covering the risks we face. An annual report on our enterprise risks, including cybersecurity risks, is presented to the Audit Committee and/or the full Board of Directors (Board).

While management is responsible for the day-to-day management of cybersecurity risks, our Board and its Audit Committee have ongoing oversight roles. The Audit Committee reviews and discusses with management, including reports from our Chief Innovation Officer, at least annually:
•the adequacy and effectiveness of our information technology security processes and procedures,
•the assessment of risks and threats to our information technology systems,
•the internal controls regarding information technology security and cybersecurity, and
•the steps management has taken to monitor and mitigate information technology security and cybersecurity risks.

The Audit Committee also periodically receives reports on notable cybersecurity incidents and briefs the full Board on these matters.

Item 3. Legal Proceedings.

Below is a discussion of pending legal proceedings not otherwise required to be disclosed in our Notes to Consolidated Financial Statements. Refer to Note 10 for further discussion.

In addition to the proceedings discussed below and in Note 10, we are involved periodically in ordinary routine litigation incidental to our business and not required to be disclosed, some of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief.

United States (U.S.) Securities and Exchange Commission (SEC) regulations require us to disclose environmental proceedings involving a governmental authority if we reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations, we use a threshold of $1 million for purposes of determining whether disclosure of any such environmental proceedings is required.

Management does not believe, based on currently available information, that the outcome of any currently pending legal proceeding will have a material adverse effect on our financial condition; although individual or cumulative outcomes could be material to our operating results for a particular period, depending on the nature and magnitude of the outcome and the operating results for the period.

Water Rights Adjudications

Our operations in the western U.S. require significant secure quantities of water for mining and ore processing activities, and related support facilities. Continuous operation of our mines is dependent on, among other things, our ability to maintain our water rights and claims and the continuing physical availability of the water supplies. In the arid western U.S., where certain of our mines are located, water rights are often contested, and disputes over water rights are generally time-consuming, expensive and not necessarily dispositive unless they resolve both actual and potential claims. The loss of a water right or a currently available water supply could force us to curtail operations, or force premature closures, thereby increasing and/or accelerating costs or foregoing profitable operations.

At our North America operations, certain of our water supplies are supported by surface water rights, which give us the right to use public waters for a statutorily defined beneficial use at a designated location. In Arizona, where our operations use both surface and groundwater, we are a participant in an active adjudication in which Arizona courts have been attempting, for 50 years, to quantify and prioritize surface water claims for the Gila River system, one of the state’s largest river systems. This Gila River adjudication primarily affects our Morenci, Safford (including Lone Star) and Sierrita mines. The Gila River adjudication is addressing the state law claims of thousands of competing users, including us, as well as significant federal water claims that are potentially adverse to the state law claims of both surface water and groundwater users. Groundwater is treated differently from surface water under Arizona law,
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which historically allowed landowners to pump unlimited quantities of subsurface water, subject only to the requirement of putting it to “reasonable use.” However, court decisions in the adjudication have concluded that some subsurface water constitutes “subflow” that is to be treated legally as surface water and is therefore subject to the Arizona doctrine of prior appropriation and to the adjudication, and potentially unavailable to groundwater pumpers, including us, in the absence of valid surface water claims. Any re-characterization of groundwater as surface water could affect the ability of consumers, farmers, ranchers, municipalities, and industrial users like us to continue to access water supplies that have been relied on for decades. Because we are a user of both groundwater and surface water in Arizona, we are an active participant in the Gila River adjudication.

In Re The General Adjudication of All Rights to Use Water in the Gila River System and Sources, Maricopa County, Superior Court, Cause Nos. W-1 (Salt), W-2 (Verde), W-3 (Upper Gila), and W-4 (San Pedro). This case was originally initiated in 1974 with the filing of a petition with the Arizona State Land Department and was consolidated and transferred to the Maricopa County Superior Court in 1981. The principal parties, in addition to us, include: Arizona Public Service Company, ASARCO, LLC; BHP Copper, Inc; the state of Arizona; various cities and towns and water companies; the Gila Valley Irrigation District; the Franklin Irrigation District; the San Carlos Irrigation and Drainage District; the Salt River Project; the San Carlos Apache Tribe; the Gila River Indian Community; and the U.S. on behalf of those tribes, on its own behalf, and on behalf of the White Mountain Apache Tribe, the Fort McDowell Mohave-Apache Indian Community, the Salt River Pima-Maricopa Indian Community, and the Payson Community of Yavapai Apache Indians. Prior to January 1, 1983, various Indian tribes filed separate suits in the U.S. District Court in Arizona claiming superior rights to water being used by many other parties, including us, and claiming damages for prior use in derogation of their allegedly superior rights. These federal proceedings have been stayed in favor of the adjudications pending in Arizona state courts, and some of the federal suits have since been settled.

In 2005, the Maricopa County Superior Court directed the Arizona Department of Water Resources (ADWR) to prepare detailed recommendations regarding the delineation of the “subflow” zone of the San Pedro River, a tributary of the Gila River. Subsurface water within the subflow zone is presumed to constitute appropriable subflow rather than groundwater. Although we have minimal interests in the San Pedro River Basin, a decision that re-characterizes groundwater in that basin as appropriable subflow may set a precedent for other river systems in Arizona that could have material implications for many commercial, industrial, municipal and agricultural users of groundwater, including our Arizona operations. In 2017, the court approved ADWR’s proposed subflow zone maps; water pumped from wells located inside the mapped subflow zone is now presumed to be appropriable subflow. No party has appealed that decision.

ADWR is now in the process of preparing subflow zone delineations for the applicable watercourses in the Verde River watershed. In December 2021, ADWR issued a report proposing a subflow zone delineation for the Verde River mainstem and Sycamore Creek and objections to that report were submitted in May 2022. While we do not have any active mining operations in the Verde River watershed that would be impacted by this phase of the adjudication, we filed a set of limited objections on issues that could set a precedent for other watersheds in Arizona that could have material implications for many users of groundwater, including our Arizona operations. The Special Master has directed ADWR to submit revised subflow zone delineations consistent with our objections.

In 2014, ADWR submitted a proposal for the development of procedures for “cone of depression” analyses to determine whether a well located outside of the subflow zone creates a cone of depression that intersects the subflow zone. Based on these cone of depression analyses, wells outside of the subflow zone could be subject to the adjudications pending in Arizona state courts. In the absence of a valid surface water claim to support the pumping, owners of wells deemed to be depleting the subflow zone through their cones of depression may be subject to claims that they must refrain from pumping subflow or must pay damages. In January 2017, ADWR issued a report containing its recommended cone of depression test.

In November 2018, the Special Master for the Gila River adjudication issued a final decision rejecting ADWR’s recommended cone of depression test, adopting our position that a numeric model capable of accounting for complexities of the aquifer system should be used. However, the Special Master confirmed that the cone of depression test would be the initial test for determining which wells are subject to the adjudications, rather than proving that a well is pumping subflow or establishing how much of a well’s water production is subflow. Such matters will be determined by a subsequent “subflow depletion test,” which is currently under development. While some of our adversaries objected to the Special Master’s final decision, in July 2022, the Arizona Superior Court issued a decision affirming the Special Master’s decision in all respects. No party has appealed that decision.

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In December 2018, ADWR submitted its initial report on the “subflow depletion test,” noting that the test will specify the methodology a well owner must use to quantify the portion of the water drawn from a well that is subflow as opposed to groundwater. In February 2024, ADWR issued a report setting forth its proposed subflow depletion test, and objections were filed in April 2024. The Special Master ordered ADWR to file an addendum to its report concerning various issues raised in the objections. A status conference is scheduled for February 2025.

An issue litigated in the 2018 proceeding concerned whether for the subflow depletion test the subflow zone should be represented in the numeric model as extending only as deep as the bottom of the floodplain alluvium or extend all the way down to bedrock. In August 2021, the Special Master issued an order recognizing our position that if the vertical extent of the subflow zone is extended below the floodplain alluvium, it would result in overstated depletion calculations. Accordingly, the Special Master ordered that the vertical boundary of the subflow zone be restricted to the floodplain alluvium. No party has appealed that decision, and we expect the guidance from the Special Master’s order to be reflected in the subflow depletion test.

In proceedings separate from the development of the subflow depletion test, in June 2020, the Special Master designated legal questions to be resolved concerning a well owner’s ability to obtain a surface water right for subsurface water that, while initially believed to be non-appropriable groundwater, is ultimately determined to be appropriable subflow. In April 2021, the Special Master ruled that, for uses initiated after enactment of the 1919 permitting statute, a well owner may not pursue a surface water right for subsurface water now unless the well owner filed an application for a permit to appropriate prior to initiating the water use. We, along with allied parties, have objected to the Special Master’s ruling and are awaiting further proceedings before the Arizona Superior Court. Regardless of the outcome in the Arizona Superior Court, we anticipate this issue will be appealed to the Arizona Supreme Court.

As part of the adjudications, the U.S. has asserted numerous claims for express and implied “reserved” surface water and groundwater rights on Indian and non-Indian federal lands throughout Arizona. These claims are related to reservations of federal land for specific purposes (e.g., Indian reservations, national parks, military bases and wilderness areas). Unlike state law-based water rights, federal reserved water rights are given priority in the “prior appropriation” system based on the date the land was reserved, not the date that water was first used on the land. In addition, federal reserved water rights may enjoy greater protection from groundwater pumping than is accorded to state law-based water rights.

In multiple instances, the U.S. asserts a right to all water in a particular watershed that was not effectively appropriated under state law prior to the establishment of the federal reservation. This creates risks for both surface water users and groundwater users because such expansive claims may severely impede competing uses of water within the same watershed. Because there are numerous federal reservations in watersheds across Arizona, the reserved water right claims of the U.S. pose a significant risk to multiple operations, including Morenci and Safford (including Lone Star) in the Upper Gila River watershed, and Sierrita in the Santa Cruz watershed. Because federal reserved water rights may adversely affect water uses at each of these operations, we have been actively involved in litigation over these claims. Because federal reserved water rights have not yet been quantified, the task of determining how much water each federal reservation may use has been left to the Arizona Superior Court handling the Gila River adjudication. Various “contested cases” to quantify reserved water rights for particular federal reservations in Arizona are currently pending, four of which have been resolved at this time. The first resolved decision was issued in In re Aravaipa Canyon Wilderness Area, which pertained to the U.S.’s claims to water for the Aravaipa Canyon Wilderness Area. The court issued a decision in December 2018 supportive of our position on almost all issues, rejecting the U.S.’s argument that wilderness areas are entitled to all water that was not appropriated at the time the reservation was created. The second resolved decision was issued in In re Redfield Canyon Wilderness Area, which was another case pertaining to claims for a wilderness area. The court issued its decision in August 2022 supportive of our position on almost all issues, denying the U.S.’s federal reserved water rights claims for the wilderness area. The U.S. declined to pursue an interlocutory appeal in either of the In re Aravaipa Canyon Wilderness Area or In re Redfield Canyon Wilderness Area cases. The third resolved decision was issued in In re San Pedro Riparian National Conservation Area, which pertained to the U.S.’s claims to water for a national conservation area. The court issued its decision in August 2023 supportive of our position on nearly all issues, rejecting the U.S.’s argument that quantification was based on a more lenient standard than the “minimal need” doctrine, and holding that the U.S. may not obtain a federal reserved right to “optimal” flows to support the riparian and aquatic resources. The court adopted our proposed period of record for quantifying the stream, and therefore adopted our proposed streamflow, and rejected the U.S.’s claims for “streamflow augmentation” and claims to water from various point sources. We anticipate that a decree will be entered in 2025. It is unknown whether the U.S. will pursue an interlocutory appeal. The fourth resolved decision was issued in, In re Fort
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Huachuca, which involved the U.S.’s claims to water for an Arizona army base. Trial concluded in February 2017. The court issued its decision in September 2024 supportive of our position on almost all issues and entered a decree in December 2024. The result was an approximate 80% reduction of the total acre-feet per year claimed by the U.S. It is unknown whether the U.S. will pursue an interlocutory appeal.

In addition, in January 2023, the U.S. filed several federal reserved water rights claims for wilderness areas in portions of the Verde River watershed, as well as a claim for the Verde River pursuant to the Wild and Scenic Rivers Act, claiming all unappropriated flow within each of the wilderness areas, along with alternative claims to specific stream flows. In reliance on the favorable precedent created in the cases discussed above, we successfully defeated the claims to all unappropriated flow on summary judgment. We anticipate that the Special Master will establish litigation schedules concerning the other claims to specific stream flows.

Given the legal and technical complexity of these adjudications, their long history, and their long-term legal, economic and political implications, it is difficult to predict the timing or the outcome of these proceedings. If we are not able to satisfactorily resolve the issues being addressed in the adjudications, our water uses could be diminished or curtailed, and our operations and any future expansions at Morenci, Safford (including Lone Star) and Sierrita could be adversely affected unless we are able to acquire alternative water sources.

Item 4. Mine Safety Disclosures.

Our highest priority is the health, safety and well-being of our workforce. We believe health and safety considerations are integral to, and fundamental for, all other functions in our organization, and we understand that the health and safety of our workforce is critical to our operational efficiency and long-term success. Our global health and safety strategy, “Safe Production Matters,” is focused on fatality prevention, eliminating systemic root causes of incidents and continuous improvement through robust management systems, which are supported by leaders empowering our teams to work safely. Foundational to our Safe Production Matters strategy is our Fatal Risk Management (FRM) program. The goal of our FRM program is to achieve zero workplace fatalities by raising awareness to fatal risks and the measures necessary to mitigate them.

Refer to Exhibit 95.1 for mine safety disclosures required in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of SEC Regulation S-K.

Information About Our Executive Officers.

Certain information as of February 14, 2025, about our executive officers is set forth in the following table and accompanying text:
NameAgePosition or Office
Kathleen L. Quirk61President and Chief Executive Officer
Maree E. Robertson49Executive Vice President and Chief Financial Officer
Richard C. Adkerson78Chairman of the Board of Directors
Stephen T. Higgins67Executive Vice President and Chief Administrative Officer
Douglas N. Currault II60Executive Vice President and General Counsel
Kathleen L. Quirk has served as Chief Executive Officer (CEO) since June 2024, as President since February 2021 and as a director of the Board of Directors (Board) since February 2023. Ms. Quirk previously served as Chief Financial Officer (CFO) from December 2003 to March 2022, Executive Vice President from March 2007 to February 2021, Senior Vice President from December 2003 to March 2007 and Treasurer from February 2000 to August 2018. Ms. Quirk also serves on the Board of Directors of Vulcan Materials Company.

Maree E. Robertson has served as Executive Vice President since July 2024 and CFO since March 2022. She previously served as Senior Vice President from March 2022 to June 2024. Prior to joining the company, Ms. Robertson served as CFO, Energy and Minerals of Rio Tinto Group, a multinational metals and mining company, from September 2019 to December 2021. Prior to joining Rio Tinto, Ms. Robertson had a 17-year career at BHP Group, a multinational natural resources company, serving in a broad range of international finance functions, including Vice President, Finance, Petroleum USA; Head of Finance, Conventional and Potash, Petroleum, USA; Vice President, Finance, Potash Canada; and Vice President, Finance, Minera Escondida Ltda.

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Richard C. Adkerson has served as Chairman of the Board since February 2021 and has been a director since October 2006. Mr. Adkerson previously served as CEO from December 2003 to June 2024, Vice Chairman of the Board from May 2013 to February 2021, President from January 2008 to February 2021 and also from April 1997 to March 2007, and CFO from October 2000 to December 2003.

Stephen T. Higgins has served as Executive Vice President since July 2024 and Chief Administrative Officer since January 2019. Mr. Higgins previously served as Senior Vice President from August 2018 to June 2024, Vice President – Sales and Marketing from March 2007 to August 2018 and President of Freeport-McMoRan Sales Company Inc. from April 2006 to August 2019.

Douglas N. Currault II has served as Executive Vice President since July 2024 and General Counsel since October 2019. Mr. Currault previously served as Senior Vice President from October 2019 to June 2024, Deputy General Counsel from January 2015 to October 2019, Assistant General Counsel from January 2008 to January 2015, Secretary from May 2007 to December 2019 and Assistant Secretary from February 2000 to May 2007.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Unregistered Sales of Equity Securities

There were no unregistered sales of equity securities during the quarter ended December 31, 2024.

Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “FCX.” At January 31, 2025, there were 9,109 holders of record of our common stock.

Common Stock Dividends

In February 2021, our Board of Directors (Board) reinstated a cash dividend on our common stock (base dividend) at an annual rate of $0.30 per share, and in November 2021, the Board approved a variable cash dividend on our common stock at an annual rate of $0.30 per share. The combined annual rate of the base dividend and the variable dividend totaled $0.60 per share in 2024 and 2023.

In December 2024, our Board declared cash dividends totaling $0.15 per share on our common stock (including a $0.075 per share quarterly base cash dividend and a $0.075 per share variable, performance-based cash dividend), which was paid on February 3, 2025, to shareholders of record as of January 15, 2025. Based on current market conditions, the base and variable dividends on our common stock are anticipated to total $0.60 per share for 2025 (including the dividends paid on February 3, 2025), comprised of a $0.30 per share base dividend and $0.30 per share variable dividend. The declaration and payment of dividends (base or variable) is at the discretion of our Board and will depend upon our financial results, cash requirements, global economic conditions and other factors deemed relevant by our Board. See “Cautionary Statement” in Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk” and Note 8 for further discussion.

Issuer Purchases of Equity Securities

The following table sets forth information with respect to shares of FCX common stock purchased by us during the quarter ended December 31, 2024, and the approximate dollar value of shares that may yet be purchased pursuant to our share repurchase program:
Period(a) Total
Number of
Shares Purchased		(b) Average
Price Paid Per Share
(c) Total Number of
Shares Purchased as Part of Publicly Announced Plans or Programsa
(d) Approximate Dollar Value of Shares That May
Yet Be Purchased Under the Plans or Programsa
October 1-31, 2024—  $— — $3,105,744,136 
November 1-30, 2024— $— — $3,105,744,136 
December 1-31, 2024— $— — $3,105,744,136 
Total— $— — 
a.On November 1, 2021, our Board approved a share repurchase program authorizing repurchases of up to $3.0 billion of our common stock. On July 19, 2022, our Board authorized an increase in the share repurchase program up to $5.0 billion. The share repurchase program does not obligate us to acquire any specific amount of shares and does not have an expiration date.

The timing and amount of the share repurchases is at the discretion of management and will depend on a variety of factors. The share repurchase program may be modified, increased, suspended or terminated at any time at our Board’s discretion. See Item 1A. “Risk Factors” and Note 8 for further discussion.

Item 6. Reserved.

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Items 7. and 7A.  Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk.

In Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk (MD&A), “we,” “us” and “our” refer to Freeport-McMoRan Inc. and its consolidated subsidiaries. The results of operations reported and summarized below include forward-looking statements that are not guarantees of future performance and are not necessarily indicative of future operating results (refer to “Cautionary Statement” below for further discussion). References to “Notes” are Notes included in our Notes to Consolidated Financial Statements. Throughout MD&A, all references to income or losses per share are on a diluted basis.

This section of our Form 10-K discusses the results of operations for the years 2024 and 2023 and comparisons between these years. Discussion of the results of operations for the year 2022 and comparisons between the years 2023 and 2022 are not included in this Form 10-K and can be found in Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk” contained in Part II of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

OVERVIEW

We are a leading international metals company with the objective of being foremost in copper. Headquartered in Phoenix, Arizona, we operate large, long-lived, geographically diverse assets with significant proven and probable mineral reserves of copper, gold and molybdenum. We are one of the world’s largest publicly traded copper producers. Our portfolio of assets includes the Grasberg minerals district in Indonesia, one of the world’s largest copper and gold deposits; and significant operations in North America and South America, including the large-scale Morenci minerals district in Arizona and the Cerro Verde operation in Peru.

Our results for 2024 reflect solid execution of our operating plans and we are committed to enhancing productivity, managing costs and capital and advancing opportunities for long-term profitable growth and value creation. We believe the actions we have taken in recent years to strengthen our balance sheet and maintain flexible organic growth options will allow us to continue to execute our business plans, and reliably and responsibly generate cash flows to pursue value-enhancing organic growth options and return cash to shareholders.

We believe that we have a high-quality portfolio of long-lived copper assets positioned to generate long-term value, and we remain focused on executing our operating and investment plans. Our underground mining operations at the Grasberg minerals district in Indonesia continue to perform well, with copper production increasing in each of the past three years. During 2024, construction of PT Freeport Indonesia’s (PT-FI) new smelter and precious metals refinery (PMR) (collectively, PT-FI’s new downstream processing facilities) in Eastern Java, Indonesia were completed and as part of start-up activities, PT-FI commenced gold production from the PMR in December 2024. In October 2024, during start-up activities of the new smelter, a fire occurred requiring a temporary suspension of smelting operations to complete repairs. PT-FI expects repairs to be completed by mid-2025 and ramp-up to full capacity to be achieved by year-end 2025.

We are progressing initiatives across our North America and South America operations by incorporating new applications, technologies and data analytics to our leaching processes. Incremental copper production from these initiatives totaled 214 million pounds in 2024, compared with a total of 144 million pounds in 2023. We have projects underway to apply recent operational enhancements to our leaching processes on a larger scale and are testing new innovative technology applications that we believe have the potential for significant increases in recoverable metal from leach stockpiles beyond the current run rate.

We believe we benefit from significant copper reserves and resources with embedded growth options, an experienced team and exposure to markets with a favorable fundamental outlook.

Net income attributable to common stock totaled $1.9 billion in 2024 and $1.8 billion in 2023. Our results in 2024, compared to 2023, primarily reflect higher average realized copper and gold prices and higher gold sales volumes, partly offset by higher operating costs and higher income attributable to noncontrolling interests primarily related to higher operating income at PT-FI. Refer to “Consolidated Results” for discussion of items impacting our consolidated results for the two years ended December 31, 2024.

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At December 31, 2024, we had consolidated debt of $8.9 billion and consolidated cash and cash equivalents of $3.9 billion, $4.7 billion including current restricted cash and cash equivalents associated with a portion of PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks. Net debt totaled $1.06 billion, excluding $3.2 billion of debt for PT-FI’s new downstream processing facilities. Refer to “Net Debt” for reconciliations of consolidated debt, consolidated cash and cash equivalents and current restricted cash associated with PT-FI's export proceeds to net debt.

At December 31, 2024, we had $3.0 billion of availability under our revolving credit facility, and PT-FI and Cerro Verde had $1.5 billion and $350 million, respectively, of availability under their revolving credit facilities. In November 2024, we repaid $0.7 billion in scheduled senior note maturities using cash on hand and have no further senior note maturities until 2027. Refer to Note 6 and “Capital Resources and Liquidity” for further discussion of our debt.

We have significant mineral reserves, mineral resources and future development opportunities within our portfolio of mining assets. At December 31, 2024, our estimated consolidated recoverable proven and probable mineral reserves totaled 97.0 billion pounds of copper, 23.0 million ounces of gold and 3.16 billion pounds of molybdenum. Refer to Note 15 and “Critical Accounting Estimates – Mineral Reserves” for further discussion.

During 2024, production from our mines totaled 4.2 billion pounds of copper, 1.9 million ounces of gold and 80 million pounds of molybdenum. Following is the allocation of our consolidated copper, gold and molybdenum production in 2024 by geographic location:
CopperGoldMolybdenum
North America29 %1 %75 %
a
South America28 — 25 
Indonesia43 99 — 
100 %100 %100 %
a.Our North America copper mines produced 38% of consolidated molybdenum production, and our Henderson and Climax molybdenum mines produced 37%.
Copper production from three of our mines (the Morenci mine in North America, the Cerro Verde mine in Peru and the Grasberg minerals district in Indonesia) together totaled 77% of our consolidated copper production in 2024.

OUTLOOK

Our financial results vary as a result of fluctuations in market prices primarily for copper, gold and, to a lesser extent, molybdenum, as well as other factors. World market prices for these commodities have fluctuated historically and are affected by numerous factors beyond our control. Refer to “Markets,” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion. Because we cannot control the prices of our products, the key measures that management focuses on in operating our business are sales volumes, unit net cash costs, operating cash flows and capital expenditures. The forward-looking statements in the below section and elsewhere in this annual report on Form 10-K are based on current market conditions, speak only as of the filing date of this annual report on Form 10-K, are based on several assumptions and are subject to significant risks and uncertainties. Refer to “Cautionary Statement” below.

Consolidated Sales Volumes  
Following are our projected consolidated sales volumes for 2025 and actual consolidated sales volumes for 2024:
20252024
(Projected)(Actual)
Copper (millions of recoverable pounds):
   
North America copper mines1,360  1,257 
South America mining1,090  1,177 
Indonesia mining1,550  1,632 
Total4,000 4,066 
Gold (thousands of recoverable ounces)
1,625  1,837 
Molybdenum (millions of recoverable pounds)
88 
a
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a.Includes 53 million pounds from our North America and South America copper mines and 35 million pounds from our Molybdenum mines.

Projected sales volumes are dependent on operational performance; Indonesia regulatory approval to export copper concentrate until repairs and full ramp-up of PT-FI’s new smelter are complete; weather-related conditions; timing of shipments and other factors. For further discussion of other important factors that could cause results to differ materially from projections, refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024.

Consolidated Unit Net Cash Costs
Consolidated unit net cash costs (net of by-product credits) for our copper mines are expected to average $1.60 per pound of copper for the year 2025, based on achievement of current sales volume estimates (including estimates for copper concentrate exports from Indonesia) and cost estimates and assuming average prices of $2,700 per ounce of gold and $20.00 per pound of molybdenum for the year 2025.

Quarterly unit net cash costs vary with fluctuations in sales volumes, including the ratio of copper and gold sales within a period, and realized prices, primarily for gold and molybdenum. The impact of price changes on consolidated unit net cash costs for the year 2025 would approximate $0.04 per pound of copper for each $100 per ounce change in the average price of gold and $0.03 per pound of copper for each $2 per pound change in the average price of molybdenum.

Consolidated Operating Cash Flows
Our consolidated operating cash flows vary with sales volumes; prices realized from copper, gold and molybdenum sales; production costs; income taxes; other working capital changes; and other factors. Our consolidated operating cash flows are estimated to approximate $6.2 billion for the year 2025, based on current sales volume and cost estimates, and assuming average prices of $4.00 per pound of copper, $2,700 per ounce of gold and $20.00 per pound of molybdenum for the year 2025. Estimated consolidated operating cash flows in 2025 also reflect a projected income tax provision of $2.6 billion (refer to “Consolidated Results – Income Taxes” for further discussion of our projected income tax rate). The impact of price changes on operating cash flows for the year 2025 would approximate $375 million for each $0.10 per pound change in the average price of copper, $140 million for each $100 per ounce change in the average price of gold and $135 million for each $2 per pound change in the average price of molybdenum.

Consolidated Capital Expenditures
Following is a summary of expected capital expenditures for the year 2025 (in billions):
Major mining projects$2.8 
a
PT-FI’s new downstream processing facilities0.6 
b
Sustaining capital and other1.6 
Total$5.0 
a.Includes $1.1 billion for planned projects, primarily associated with underground mine development, supporting mill and power capital costs and a portion of spending on a new gas-fired combined cycle facility in the Grasberg minerals district, and expansion projects in North America, and $1.7 billion for discretionary growth projects, primarily in the Grasberg minerals district for the development of Kucing Liar and at the Bagdad mine for tailings infrastructure.
b.Excludes capitalized interest, commissioning and owner’s costs. Capital expenditures for PT-FI’s new downstream processing facilities are expected to be funded with PT-FI’s cash flows from operations and availability under PT-FI’s revolving credit facility.

We closely monitor market conditions and will adjust our operating plans, including capital expenditures, to protect our liquidity and preserve our asset values, as necessary.

MARKETS

Prices for copper, gold and molybdenum are affected by numerous factors beyond our control and can fluctuate significantly (for further discussion refer to “Risk Factors” contained in Part I, Item 1A. of our annual report on Form 10-K for the year ended December 31, 2024). The following graphs present the London Metal Exchange (LME) copper settlement prices, the London Bullion Market Association (London) PM gold prices, and the Platts Metals Daily Molybdenum Dealer Oxide weekly average prices since January 2015.
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Copper Q4.jpg
This graph presents LME copper settlement prices and the combined reported stocks of copper at the LME, Commodity Exchange Inc. (COMEX) and the Shanghai Futures Exchange from January 2015 through December 2024. Copper sales from our South America and Indonesia operations are generally based on quoted LME monthly average copper settlement prices. For the year 2024, the LME copper settlement prices averaged $4.15 per pound (ranging from a low of $3.67 per pound to a high of $4.92 per pound) and closed at $3.95 per pound on December 31, 2024. The LME copper settlement prices averaged $4.07 per pound in January 2025, and closed at $4.25 per pound on February 13, 2025.

Copper sales from our North America copper mines are generally based on prevailing COMEX monthly average copper settlement prices. For the year 2024, COMEX copper settlement prices averaged $4.22 per pound (ranging from a low of $3.69 per pound to a high of $5.12 per pound) and closed at $3.99 per pound on December 31, 2024. COMEX copper settlement prices averaged $4.25 per pound in January 2025, and closed at $4.77 per pound on February 13, 2025.

We believe fundamentals for copper are favorable with growing demand supported by copper’s critical role in the global transition to renewable power, electric vehicles and other carbon-reduction initiatives, continued urbanization in developing countries, data centers and artificial intelligence developments and growing connectivity globally.
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Gold Q4 .jpg
This graph presents London PM gold prices from January 2015 through December 2024. For the year 2024, London PM gold prices averaged $2,386 per ounce (ranging from a low of $1,985 per ounce to a high of $2,778 per ounce) and closed at $2,609 per ounce on December 31, 2024. Interest rate reductions, geopolitical tensions and strong demand from central banks positively impacted gold prices during 2024. The London PM gold prices averaged $2,710 in January 2025, and closed at $2,915 per ounce on February 13, 2025.Moly Q4.jpg
This graph presents the Platts Metals Daily Molybdenum Dealer Oxide weekly average prices from January 2015 through December 2024. For the year 2024, the weekly average prices for molybdenum averaged $21.30 per pound (ranging from a low of $19.34 per pound to a high of $23.52 per pound) and was $21.08 per pound on December 31, 2024. Overall global demand for molybdenum is driven by energy, power generation, aerospace,
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defense and construction sectors. We believe fundamentals for molybdenum are positive with favorable demand drivers and limited supply. The Platts Metals Daily Molybdenum Dealer Oxide weekly average price for January 2025 was $20.82 per pound and was $20.70 per pound on February 13, 2025.

CRITICAL ACCOUNTING ESTIMATES

MD&A is based on our consolidated financial statements, which have been prepared in conformity with generally accepted accounting principles (GAAP) in the U.S. The preparation of these statements requires that we make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider reasonable under the circumstances; however, reported results could differ from those based on the current estimates under different assumptions or conditions. The areas requiring the use of management’s estimates are also discussed in Note 1 under the subheading “Use of Estimates.” Management has reviewed the following discussion of its development and selection of critical accounting estimates with the Audit Committee of our Board of Directors (Board).

Income Taxes
Refer to Note 9, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of our consolidated income taxes.

In preparing our consolidated financial statements, we estimate the actual amount of income taxes currently payable or receivable as well as deferred income tax assets and liabilities attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rates or laws is recognized in income in the period in which such changes are enacted.

Income taxes represent a critical accounting estimate as our operations are in multiple tax jurisdictions where uncertainties arise in the application of complex tax regulations and our income tax returns are subject to examination by tax authorities in those jurisdictions who may challenge any tax position on these returns. Some of these tax regimes are defined by contractual agreements with the local government, while others are defined by general tax laws and regulations. We and our subsidiaries are subject to reviews of our income tax filings and other tax payments, and disputes can arise with the taxing authorities over the interpretation of our contracts or laws. Uncertainty in a tax position may arise because tax laws are subject to interpretation. We use significant judgment to (1) determine whether, based on the technical merits, a tax position is more likely than not to be sustained upon examination by taxing authorities and (2) measure the amount of tax benefit that qualifies for recognition.

A valuation allowance is provided for those deferred income tax assets for which available information, including positive and negative evidence, suggests that the related benefits will not be realized. In determining the amount of the valuation allowance, we consider carryback opportunities, future reversals of existing taxable temporary differences, prudent and feasible tax planning strategies in each jurisdiction, as well as future taxable income exclusive of reversing temporary differences. If we determine that we will not realize all or a portion of our deferred income tax assets, we will increase our valuation allowance. Conversely, if we determine that we will ultimately be able to realize all or a portion of the related benefits for which a valuation allowance has been provided, all or a portion of the related valuation allowance will be reduced. Refer to Note 9 for further discussion of our valuation allowances.

On January 1, 2023, the provisions of the U.S. Inflation Reduction Act of 2022 (the Act) became applicable to us. The Act includes, among other provisions, a new Corporate Alternative Minimum Tax (CAMT) of 15% on the adjusted financial statement income (AFSI) of corporations with average annual AFSI exceeding $1.0 billion over a three-year period.

In September 2024, the Internal Revenue Service (IRS) issued proposed regulations that provide guidance on the application of the CAMT, which are not final and subject to change. Based on the proposed guidance released by the IRS, we determined that the provisions of the Act did not impact our financial results for the years 2024 or 2023.

In December 2021, the Organisation for Economic Cooperation and Development (OECD) published a framework for Pillar Two of the Global Anti-Base Erosion Rules, which was designed to coordinate participating jurisdictions in updating the international tax system to ensure that large multinational companies pay a minimum level of income
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tax. Recommendations from the OECD regarding a global minimum income tax and other changes are being considered and/or implemented in jurisdictions where we operate. At current metals market prices, we do not expect enactment of the recommended framework in jurisdictions where we operate to materially impact our financial results.

We have uncertain tax positions related to income tax assessments in Peru and Indonesia, including penalties and interest, which have not been recorded at December 31, 2024. Final taxes paid may be dependent upon many factors, including negotiations with taxing authorities. In certain jurisdictions, we pay a portion of the disputed amount before formally appealing an assessment. Such payment is recorded as a receivable if we believe the amount is collectible. Refer to Note 10 for further discussion.

Environmental Obligations
Refer to Notes 1 and 10, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of environmental obligations, including a summary of changes in our estimated environmental obligations for the three years ended December 31, 2024.

Our current and historical operating activities are subject to various national, state and local environmental laws and regulations that govern emissions of air pollutants; discharges of water pollutants; generation, handling, storage, treatment, transportation and disposal of hazardous substances, hazardous wastes and other toxic materials; and remediation, restoration and reclamation of environmental contamination, and compliance with these laws and regulations requires significant expenditures. Environmental expenditures are charged to expense or capitalized, depending upon their future economic benefits. The guidance provided by U.S. GAAP requires that liabilities for contingencies be recorded when it is probable that obligations have been incurred, and the cost can be reasonably estimated. At December 31, 2024, environmental obligations recorded in our consolidated balance sheet totaled $2.0 billion, which reflect obligations for environmental liabilities attributed to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 or analogous state programs and for estimated future costs associated with environmental matters.

Accounting for environmental obligations represents a critical accounting estimate because (i) changes to environmental laws and regulations and/or circumstances affecting our operations could result in significant changes to our estimates, which could have a significant impact on our results of operations, (ii) we will not incur most of these costs for a number of years, requiring us to make estimates over a long period, (iii) calculating the discounted cash flows for certain of our environmental obligations requires management to estimate the amounts and timing of projected cash flows and make long-term assumptions about inflation rates and (iv) changes in estimates used in determining our environmental obligations could have a significant impact on our results of operations.

We perform a comprehensive annual review of our environmental obligations and also review changes in facts and circumstances associated with these obligations at least quarterly. Judgments and estimates are based upon currently available facts, existing technology, presently enacted laws and regulations, remediation experience, whether we are a potentially responsible party (PRP), the ability of other PRPs to pay their allocated portions and take into consideration reasonably possible outcomes. Our cost estimates can change substantially as additional information becomes available regarding the nature or extent of site contamination, updated cost assumptions (including increases and decreases to cost estimates), changes in the anticipated scope and timing of remediation activities, the settlement of environmental matters, required remediation methods and actions by or against governmental agencies or private parties.

Asset Retirement Obligations
Refer to Notes 1 and 10, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of reclamation and closure costs, including a summary of changes in our asset retirement obligations (AROs) for the three years ended December 31, 2024.

We record the fair value of our estimated AROs associated with tangible long-lived assets in the period incurred. Fair value is measured as the present value of cash flow estimates after considering inflation and a market risk premium. Our cost estimates are reflected on a third-party cost basis and comply with our legal obligation to retire tangible long-lived assets in the period incurred. These cost estimates may differ from financial assurance cost estimates for reclamation activities because of a variety of factors, including obtaining updated cost estimates for reclamation activities, the timing of reclamation activities, changes in scope and the exclusion of certain costs not
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considered reclamation and closure costs. At December 31, 2024, AROs recorded in our consolidated balance sheet totaled $3.7 billion.

Generally, ARO activities are specified by regulations or in permits issued by the relevant governing authority, and management’s judgment is required to estimate the extent and timing of expenditures. Accounting for AROs represents a critical accounting estimate because (i) we will not incur most of these costs for a number of years, requiring us to make estimates over a long period, (ii) reclamation and closure laws and regulations could change in the future, we may commit to taking additional closure actions and/or circumstances affecting our operations could change, (iii) the methods used or required to plug and abandon non-producing oil and gas wellbores, remove platforms, tanks, production equipment and flow lines, and restore the wellsite could change, (iv) calculating the fair value of our AROs requires management to estimate projected cash flows, make long-term assumptions about inflation rates, determine our credit-adjusted, risk-free interest rates and determine market risk premiums that are appropriate for our operations and (v) given the magnitude of our estimated reclamation, mine closure and wellsite abandonment and restoration costs, changes in any or all of these estimates could have a significant impact on our results of operations.

Mineral Reserves
Refer to Note 15, and Items 1. and 2. “Business and Properties” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further information regarding, and risks associated with, our estimated recoverable proven and probable mineral reserves.

Recoverable proven and probable mineral reserves were determined from the application of relevant modifying factors to geological data, in order to establish an operational, economically viable mine plan, and have been prepared in accordance with the disclosure requirements of Subpart 1300 of U.S. Securities and Exchange Commission Regulation S-K. The determination of mineral reserves represents a critical accounting estimate because it involves numerous uncertainties with respect to the ultimate geology of the ore bodies, including quantities, grades and recoveries. Estimating the quantity and grade of mineral reserves requires us to determine the size, shape and depth of our ore bodies by analyzing geological data, such as samplings of drill holes, tunnels and other underground workings. In addition to the geology of our mines, assumptions are required to determine the economic feasibility of mining these reserves, including estimates of future commodity prices, the mining methods we use and the related costs incurred to develop and mine our mineral reserves. Our estimates of recoverable proven and probable mineral reserves are prepared by and are the responsibility of our employees. These estimates are reviewed and verified regularly by independent experts in mining, geology and reserve determination.

Our estimated recoverable proven and probable mineral reserves at December 31, 2024, were determined using metal price assumptions of $3.25 per pound of copper, $1,600 per ounce of gold and $12.00 per pound of molybdenum. The following table summarizes changes in our estimated consolidated recoverable proven and probable mineral reserves during 2024:
Copper
(billion pounds)
Gold
(million ounces)
Molybdenum
(billion pounds)
Reserves at December 31, 2023a
104.1 24.5 3.34 
Net revisions(3.0)
b
0.4 (0.10)
Production(4.2)(1.9)(0.08)
Reserves at December 31, 2024a,c
97.0 23.0 3.16 
a.Includes estimated recoverable metals contained in stockpiles. See below for additional discussion of recoverable copper in stockpiles.
b.Revisions are primarily the result of higher cost assumptions and updated geologic models.
c.May not foot because of rounding.

As discussed in Note 1, we depreciate our life-of-mine mining and milling assets and values assigned to proven and probable mineral reserves using the unit-of-production (UOP) method based on our estimated recoverable proven and probable mineral reserves. Because the economic assumptions used to estimate mineral reserves may change from period to period and additional geological data is generated during the course of operations, estimates of mineral reserves may change, which could have a significant impact on our results of operations, including changes to prospective depreciation rates and impairments of long-lived asset carrying values. Based on projected copper sales volumes, if estimated copper reserves at our mines were 10% higher at December 31, 2024, we estimate that our annual depreciation, depletion and amortization (DD&A) expense for 2025 would decrease by approximately
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$110 million (approximately $43 million to net income attributable to common stock), and a 10% decrease in copper reserves would increase DD&A expense by approximately $137 million (approximately $53 million to net income attributable to common stock). We perform annual assessments of our existing assets in connection with the review of mine operating and development plans. If it is determined that assigned asset lives do not reflect the expected remaining period of benefit, any change could affect prospective DD&A rates.

As discussed below, we review and evaluate our long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates of recoverable proven and probable mineral reserves could have an impact on our assessment of asset recoverability.

Recoverable Copper in Stockpiles
Refer to Note 1 for further discussion of our accounting policy for recoverable copper in mill and leach stockpiles, including adjustments to stockpile inventory volumes and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for risks associated with implementation of new technologies associated with the recovery of copper in leach stockpiles.

We record, as inventory, applicable costs for copper contained in mill and leach stockpiles that are expected to be processed in the future based on proven processing technologies. Mill and leach stockpiles are evaluated periodically to ensure that they are stated at the lower of weighted-average cost or net realizable value.

Accounting for recoverable copper from mill and leach stockpiles represents a critical accounting estimate because (i) it is impracticable to determine copper contained in mill and leach stockpiles by physical count, thus requiring management to employ reasonable estimation methods and (ii) recoveries from leach stockpiles can vary significantly.

At December 31, 2024, estimated consolidated recoverable copper was 1.4 billion pounds in leach stockpiles (with a carrying value of $2.2 billion) and 0.3 billion pounds in mill stockpiles (with a carrying value of $0.4 billion).

Impairment of Long-Lived Mining Assets
Refer to Note 1, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further information regarding, and risks associated with, impairment of long-lived mining assets.

We assess the carrying values of our long-lived mining assets when events or changes in circumstances indicate that the related carrying amounts of such assets may not be recoverable. In evaluating our long-lived mining assets for recoverability, we use estimates of pre-tax undiscounted future cash flows of our mines.

Estimates of future cash flows are derived from current business plans, which are developed using near-term metal price forecasts reflective of the current price environment and management’s projections for long-term average metal prices. In addition to near- and long-term metal price assumptions, other key assumptions include estimates of commodity-based and other input costs; proven and probable mineral reserves estimates, including the timing and cost to develop and produce the mineral reserves; value beyond proven and probable mineral reserve estimates; and the use of appropriate discount rates in the measurement of fair value. We believe our estimates and models used to determine fair value are similar to what a market participant would use. As quoted market prices are unavailable for our individual mining operations, fair value is determined through the use of after-tax discounted estimated future cash flows.

During the two-year period ended December 31, 2024, no material impairments of our long-lived mining assets were recorded.

In addition to decreases in future metal price assumptions, other events that could result in future impairment of our long-lived mining assets include, but are not limited to, decreases in estimated recoverable proven and probable mineral reserves and any event that might otherwise have a material adverse effect on mine site production levels or costs.

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CONSOLIDATED RESULTS
 Years Ended December 31,
 2024 2023 
SUMMARY FINANCIAL DATA
 (in millions, except per share amounts)
Revenuesa,b
$25,455 $22,855 
Operating incomea,c
$6,864 

$6,225 

Net income attributable to common stockb,c
$1,889 
d
$1,848 
e
Diluted net income per share attributable to common stockb,c
$1.30 
d
$1.28 
e
Diluted weighted-average common shares outstanding1,445  1,443  
Operating cash flowsf
$7,160 $5,279 
Capital expenditures$4,808 $4,824 
At December 31:
Cash and cash equivalents$3,923 $4,758 
Restricted cash and cash equivalents, currentg
$888 $1,208 

Total debt, including current portion$8,948 $9,422 
a.Refer to Note 14 for a summary of revenues and operating income by operating division.
b.Includes favorable adjustments to prior period provisionally priced concentrate and cathode copper sales totaling $28 million ($9 million to net income attributable to common stock or $0.01 per share) in 2024 and $183 million ($62 million to net income attributable to common stock or $0.04 per share) in 2023 (refer to Note 12).
c.We defer recognizing profits on intercompany sales until final sales to third parties occur. Changes in these deferrals attributable to variability in intercompany volumes resulted in net additions (reductions) to operating income totaling $21 million ($(3) million to net income attributable to common stock or less than $0.01 per share) in 2024 and $64 million ($37 million to net income attributable to common stock or $0.03 per share) in 2023.
d.Includes net charges totaling $257 million ($0.18 per share), primarily associated with adjustments to PT-FI’s ARO, oil and gas charges for impairments and abandonment obligations, metals inventory adjustments, net adjustments to environmental obligations and related litigation reserves and nonrecurring labor-related charges at Cerro Verde, partly offset by net credits associated with historical tax matters at PT-FI and a reduction in accruals for uncertain U.S. tax positions.
e.Includes net charges totaling $373 million ($0.26 per share), primarily associated with net adjustments to environmental obligations and related litigation reserves, contested tax rulings issued by the Peru Supreme Court, impairment of oil and gas properties and an accrual for an administrative fine in Indonesia, partly offset by adjustments to PT-FI’s ARO.
f.Working capital and other uses totaled $29 million in 2024 and $880 million in 2023.
g.Includes $0.7 billion at December 31, 2024, and $1.1 billion at December 31, 2023, associated with a portion of PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks for 90 days in accordance with Indonesia regulations (refer to Notes 10 and 12).
Years Ended December 31,
2024 2023
SUMMARY OPERATING DATA    
Copper (millions of recoverable pounds)
    
Production 4,214 4,212 
Sales, excluding purchases4,066 4,086 
Average realized price per pound$4.21 $3.85 
Site production and delivery costs per pounda
$2.49 $2.36 
Unit net cash costs per pounda
$1.56 $1.61 
Gold (thousands of recoverable ounces)
    
Production1,880 1,993 
Sales, excluding purchases1,837 1,713 
Average realized price per ounce$2,418 $1,972 
Molybdenum (millions of recoverable pounds)
    
Production80 82 
Sales, excluding purchases78 81 
Average realized price per pound$21.77 $24.64 
a.Reflects per pound weighted-average production and delivery costs and unit net cash costs (net of by-product credits) for all copper mines, before net noncash and other costs. For reconciliations of the per pound unit net cash costs by operating division to production and delivery costs applicable to sales reported in our consolidated financial statements, refer to “Product Revenues and Production Costs.”
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Revenues
Consolidated revenues totaled $25.5 billion in 2024 and $22.9 billion in 2023. Our revenues primarily include the sale of copper concentrate, copper cathode, copper rod, gold in concentrate and anode slimes, and molybdenum. Following is a summary of changes in our consolidated revenues from 2023 to 2024 (in millions):
Consolidated revenues – 2023
$22,855 
Mining operations:
(Lower) higher sales volumes:
Copper(73)
Gold316 
Molybdenum(63)
Higher (lower) averaged realized prices:
Copper1,464 
Gold836 
Molybdenum(225)
Adjustments for prior year provisionally priced copper sales(155)
Higher Atlantic Copper revenues207 
Higher revenues from sales of purchased copper277 
Lower treatment charges142 
Higher export duties and royalties(246)
Other, including intercompany eliminations120 
Consolidated revenues – 2024
$25,455 

Sales Volumes. Copper sales volumes in 2024 were slightly lower than 2023, primarily reflecting lower ore grades and operating rates in North America, partly offset by higher ore grades and operating rates in Indonesia. Gold sales volumes were higher in 2024, compared to 2023, primarily reflecting the timing of shipments at PT-FI. Refer to “Operations” for further discussion of sales volumes at our mining operations.

Realized Prices. Our consolidated revenues can vary significantly as a result of fluctuations in the market prices of copper, gold and molybdenum. In 2024, our average realized prices, compared with 2023, were 9% higher for copper, 23% higher for gold and 12% lower for molybdenum.

Certain sales contracts for copper and gold provide final pricing in a specified future month (generally one to four months from the shipment date). We record revenues and invoice customers at the time of shipment based on then-current LME or London PM prices, which results in an embedded derivative on provisionally priced sales that are adjusted to fair value through earnings each period, using the period-end forward prices, until final pricing on the date of settlement. To the extent final prices are higher or lower than what was recorded on a provisional basis, an increase or decrease to revenues is recorded each reporting period until the date of final pricing. Accordingly, in times of rising copper and gold prices, our revenues benefit from adjustments to the final pricing of provisionally priced sales pursuant to contracts entered into in prior periods; in times of falling copper and gold prices, the opposite occurs.

Consolidated revenues include net favorable (unfavorable) adjustments to current year provisionally priced copper sales (i.e., provisionally priced sales during the years 2024 and 2023) totaling $89 million for 2024 and $(86) million for 2023. See below for discussion of adjustments related to prior year provisionally priced copper sales.

Prior Year Provisionally Priced Copper Sales. Net favorable adjustments to prior years’ provisionally priced copper sales (i.e., provisionally priced copper sales at December 31, 2023 and 2022) recorded in consolidated revenues totaled $28 million in 2024 and $183 million in 2023. Refer to “Disclosures About Market Risks – Commodity Price Risk” for further discussion of our provisionally priced copper sales, and to Note 12 for a summary of total adjustments to prior period and current period provisionally priced copper sales.

Atlantic Copper Revenues. Higher Atlantic Copper revenues of $3.0 billion in 2024, compared with $2.8 billion in 2023, primarily reflects higher copper prices.

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Sales of Purchased Copper. We purchase copper cathode primarily for processing by our Rod & Refining operations. The volumes of copper purchases vary depending on cathode production from our operations and totaled 158 million pounds in 2024 and 103 million pounds in 2023. Revenues associated with the sale of purchased copper vary with the volume of copper purchases and changes in copper prices.

Treatment Charges. Revenues from our concentrate sales are recorded net of treatment charges (i.e., fees paid to smelters that are generally negotiated annually), which will vary with the sales volumes and the price of copper. The decrease in treatment charges in 2024, compared to 2023, primarily reflects lower copper concentrate sales volumes in South America.

Export Duties and Royalties. Export duties and royalties are primarily associated with PT-FI sales. Effective March 29, 2023, PT-FI’s export duties of 2.5% were eliminated upon verification that construction progress of its new smelter exceeded 50%, but were reinstated at a rate of 7.5% in July 2023 under a revised regulation. PT-FI incurred export duties totaling $457 million in 2024 and $324 million in 2023. Royalties will vary with the volume of metal sold and the prices of copper and gold. Refer to Note 11 for discussion of PT-FI’s export duties and royalties.

Production and Delivery Costs
Consolidated production and delivery costs totaled $15.6 billion in 2024, compared with $13.6 billion in 2023. Higher production and delivery costs in 2024 primarily reflect increased costs at PT-FI associated with higher operating rates and sales volumes, and for adjustments to its ARO (refer to Note 10 for discussion of Indonesia reclamation and closure programs). Production and delivery costs also includes oil and gas charges totaling $217 million in 2024 and $70 million in 2023, mostly for impairments and assumed abandonment obligations from bankruptcies of other companies (refer to Note 10) and nonrecurring labor-related charges totaling $97 million in 2024 associated with Cerro Verde’s new collective labor agreements (CLA). Refer to Note 14 for details of production and delivery costs by operating segment.

Mining Unit Site Production and Delivery Costs Per Pound. Site production and delivery costs for our copper mining operations primarily include labor, energy and other commodity-based inputs, such as sulfuric acid, steel, reagents, liners, tires and explosives. Consolidated unit site production and delivery costs (before net noncash and other costs) for our copper mines averaged $2.49 per pound of copper in 2024 and $2.36 per pound in 2023. Refer to “Operations – Unit Net Cash Costs” for further discussion of unit net cash costs associated with our operating divisions, and to “Product Revenues and Production Costs” for reconciliations of per pound costs by operating division to production and delivery costs applicable to sales reported in our consolidated financial statements.

Our copper mining operations require significant amounts of energy, principally diesel, electricity, coal and natural gas, most of which is obtained from third parties under long-term contracts. Our take-or-pay contractual obligations for electricity totaled approximately $0.2 billion at December 31, 2024. We do not have take-or-pay contractual obligations for other energy commodities. Energy represented 16% of our copper mine site operating costs in 2024, including purchases of approximately 270 million gallons of diesel fuel; approximately 8,550 gigawatt hours of electricity at our North America and South America copper mining operations (we generate all of our power at our Indonesia mining operation); approximately 750 thousand metric tons of coal for our coal power plant in Indonesia; and approximately 2 million MMBtu (million British thermal units) of natural gas at certain of our North America mines. Based on current cost estimates, energy will approximate 16% of our copper mine site operating costs for the year 2025.

Depreciation, Depletion and Amortization
Depreciation will vary under the UOP method as a result of changes in sales volumes and the related UOP rates at our mining operations. Consolidated DD&A totaled $2.2 billion in 2024 and $2.1 billion in 2023. Our consolidated DD&A is estimated to approximate $2.5 billion for the year 2025, based on current sales volume estimates. The increase in 2025, compared to 2024, primarily reflects expected completion of commissioning activities for PT-FI’s new downstream processing facilities.

Environmental Obligations and Shutdown Costs
Environmental obligation costs reflect net revisions to our long-term environmental obligations, which vary from period to period because of changes to environmental laws and regulations, the settlement of environmental matters and/or circumstances affecting our operations that could result in significant changes in our estimates (refer to “Critical Accounting Estimates – Environmental Obligations” for further discussion). Shutdown costs include care-and-maintenance costs and any litigation, remediation or related expenditures associated with closed facilities or operations.
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Net charges for environmental obligations and shutdown costs totaled $127 million in 2024, including $82 million in net adjustments to environmental obligations. Net charges totaled $319 million in 2023, including $195 million in net adjustments to environmental obligations and $65 million associated with an adjustment to the proposed settlement of talc-related litigation. Refer to Note 10 for further discussion of environmental obligations and litigation matters.

Interest Expense, Net
Consolidated interest costs (before capitalization) totaled $710 million in 2024 and $782 million in 2023. The year 2023 included $74 million of interest charges associated with Cerro Verde’s contested tax rulings issued by the Peru Supreme Court.

Capitalized interest totaled $391 million in 2024 and $267 million in 2023. The increase in capitalized interest in 2024, compared with 2023, resulted from construction and development projects in process, primarily related to PT-FI’s new downstream processing facilities. Refer to “Operations” and “Capital Resources and Liquidity – Investing Activities” for further discussion of current development projects.

Other Income, Net
Other income, net, which totaled $362 million in 2024 and $286 million in 2023, primarily includes amounts associated with interest income, currency exchange gains and losses, and mark-to-market impacts of trust assets used to satisfy financial assurance obligations for our New Mexico mining operations. The year 2024 also includes a credit of $26 million associated with the reduction in the accrual to indemnify PT Mineral Industri Indonesia (MIND ID) from potential losses arising from historical tax disputes, and the year 2023 also includes a $69 million charge associated with Cerro Verde’s contested tax rulings issued by the Peru Supreme Court.

Income Taxes
Refer to Note 9, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of income taxes.

Following is a summary of the approximate amounts used in the calculation of our consolidated income tax provision for the years ended December 31 (in millions, except percentages):
20242023
Income (Loss)a
Effective
Tax Rate		Income Tax
(Provision)
Benefit
Income (Loss)a
Effective
Tax Rate		Income Tax
(Provision)
Benefit
U.S.b
$(533)
c
7%$36 
c
$55 —%
d
$1 
South America1,519 40%(604)1,303 40%(515)
Indonesia5,754 36%(2,089)4,830 37%(1,771)
Cerro Verde historical tax matters— N/A— (142)
e
N/A3 
PT-FI historical tax matters16 
f
N/A182 
f
(5)N/A(3)
Eliminations and other151 N/A(48)(35)N/A15 
Consolidated FCX$6,907 37%$(2,523)$6,006 38%$(2,270)
a.Represents income before income taxes, equity in affiliated companies’ net earnings and noncontrolling interests.
b.In addition to our North America mining operations, which had operating income of $0.8 billion in 2024 and $1.0 billion in 2023 (refer to Note 14), the U.S. jurisdiction reflects non-operating sites and corporate-level expenses, which include interest expense associated with our senior notes and general and administrative expenses. The U.S. jurisdiction also includes net revisions to environmental obligation estimates and charges associated with oil and gas abandonment obligations and impairments.
c.Includes net credits associated with the closure of our 2017 and 2018 U.S. federal income tax exams.
d.Includes a valuation allowance release on prior year unbenefited net operating losses.
e.Reflects net charges associated with contested tax rulings issued by the Peru Supreme Court.
f.Reflects net credits associated with closure of PT-FI’s 2021 corporate income tax audit and resolution of a framework for Indonesia disputed tax matters.

Assuming achievement of current sales volume and cost estimates and average prices of $4.00 per pound for copper, $2,700 per ounce for gold and $20.00 per pound for molybdenum, we estimate our consolidated effective tax rate for the year 2025 would approximate 40%. Changes in projected sales volumes and average prices during 2025 would incur tax impacts at estimated effective rates of 39% for Peru, 36% for Indonesia and 0% for the U.S., which excludes any impacts from the Act.
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Net Income Attributable to Noncontrolling Interests
Refer to Note 2 for ownership in our subsidiaries.

Net income attributable to noncontrolling interests, which is primarily associated with PT-FI, Cerro Verde and El Abra, totaled $2.5 billion in 2024 and $1.9 billion in 2023. In September 2024, we increased our ownership interest in Cerro Verde to 55.08% from 53.56%. Refer to Note 14 for net income attributable to noncontrolling interests for each of our business segments.

Based on achievement of current sales volume and cost estimates and assuming average prices of $4.00 per pound of copper, $2,700 per ounce of gold and $20.00 per pound of molybdenum for the year 2025, we estimate that net income attributable to noncontrolling interests will approximate $2.3 billion for the year 2025. The impact of price changes on net income attributable to noncontrolling interests for the year 2025 would approximate $0.2 billion for each $0.25 per pound change in the average price of copper for the year 2025. The actual amount will depend on many factors, including relative performance of each business segment, commodity prices, costs and other factors.

OPERATIONS
Responsible Production
Refer to Items 1. and 2. “Business and Properties” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for discussion of our involvement with the International Council on Mining & Metals and environmental (including climate) and social-related risks.

We demonstrate our responsible production performance through the Copper Mark, a comprehensive assurance framework developed specifically for the copper industry, and recently extended to other metals including molybdenum. To achieve the Copper Mark, each site is required to complete an independent external assurance process to assess conformance with various environmental, social and governance criteria. Awarded sites must be revalidated every three years. We have achieved, and are committed to maintaining, the Copper Mark and/or Molybdenum Mark, as applicable, at all of our operating sites globally.

Technology and Leaching Innovation Initiatives
We are progressing initiatives across our North America and South America operations by incorporating new applications, technologies and data analytics to our leaching processes. In late 2023, we achieved our initial incremental annual run rate target of approximately 200 million pounds of copper. Incremental copper production from these initiatives totaled 214 million pounds in 2024, compared with a total of 144 million pounds in 2023. We have projects underway to apply recent operational enhancements to our leaching processes on a larger scale and are testing new innovative technology applications that we believe have the potential for significant increases in recoverable metal from leach stockpiles beyond the current run rate. Continued success with these initiatives could contribute to favorable adjustments in recoverable copper in certain leach stockpiles and positively impact average unit net cash costs.

In addition to technology-driven leaching initiatives, we are pursuing opportunities to leverage new technologies and analytic tools in automation and operating practices with a goal of improving operating efficiencies, and reducing costs and capital intensity of our current operations and future development projects. We believe these technology and leaching initiatives are particularly important to our North America operations, which have lower ore grades.

Feasibility and Optimization Studies
We are engaged in various studies associated with potential future expansion projects primarily at our mining operations. The costs for these studies are charged to production and delivery costs as incurred and totaled $155 million in 2024 and $185 million in 2023. We estimate the costs of these studies will approximate $240 million for the year 2025, subject to market conditions and other factors.


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North America
We manage seven copper operations in North America – Morenci, Bagdad, Safford (including Lone Star), Sierrita and Miami in Arizona, and Chino and Tyrone in New Mexico. We also operate a copper smelter in Miami, Arizona. All of the North America operations are wholly owned, except for Morenci. We record our 72% undivided joint venture interest in Morenci using the proportionate consolidation method.

The North America copper operations include open-pit mining, sulfide-ore concentrating, leaching and solution extraction/electrowinning (SX/EW) facilities. A majority of the copper produced at our North America copper operations is cast into copper rod by our Rod & Refining segment. The remainder of our North America copper production is sold as copper cathode or copper concentrate, a portion of which is shipped to Atlantic Copper (our wholly owned smelter and refinery in Spain). Molybdenum concentrate, gold and silver are also produced by certain of our North America copper operations.
Development Activities. Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of risks associated with development projects.

We have substantial reserves and future opportunities in the U.S., primarily associated with existing mining operations.

We have a potential expansion project to more than double the concentrator capacity of the Bagdad operation in northwest Arizona. Bagdad’s reserve life currently exceeds 80 years and supports an expanded operation. In late 2023, we completed technical and economic studies, which indicate the opportunity to construct new concentrating facilities to increase copper production by 200 to 250 million pounds per year at estimated incremental project capital costs of approximately $3.5 billion. Expanded operations would provide improved efficiency and reduce unit net cash costs through economies of scale. Project economics indicate that the expansion would require an incentive copper price in the range of $3.50 to $4.00 per pound and approximately three to four years to complete. The decision of whether to proceed and timing of the potential expansion will take into account overall copper market conditions, availability of labor and other factors, including deployment of our autonomous haul truck fleet conversion expected by year-end 2025 and expanding housing alternatives to support long-range plans. In parallel, we are enhancing local infrastructure and advancing activities for expanded tailings infrastructure projects required under long-range plans in order to advance the potential construction timeline.

We have commenced pre-feasibility studies in the Lone Star district of Safford to define a potential significant expansion opportunity. Positive drilling conducted in recent years indicates a large, mineralized district with opportunities to pursue a further expansion project. We expect to complete these studies in 2026. The decision of whether to proceed and timing of the potential expansion will take into account results of technical and economic studies, overall copper market conditions and other factors.


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Operating Data. Following is summary operating data for the North America copper mines for the years ended December 31:
 2024 2023
Operating Data, Net of Joint Venture Interests  
Copper (millions of recoverable pounds)
  
Production 1,246 1,350 
Sales, excluding purchases1,257 1,361 
Average realized price per pound$4.29 $3.93 
Molybdenum (millions of recoverable pounds)
  
Productiona
30 30 
100% Operating Data  
Leach operations  
Leach ore placed in stockpiles (metric tons per day)609,400 692,000 
Average copper ore grade (%)0.20 0.23 
Copper production (millions of recoverable pounds)842 941 
Mill operations  
Ore milled (metric tons per day)311,700 308,500 
Average ore grade (%):
Copper0.30 0.32 
Molybdenum0.02 0.02 
Copper recovery rate (%)83.2 81.8 
Copper production (millions of recoverable pounds)601 633 
a.Refer to “Consolidated Results” for our consolidated molybdenum sales volumes, which include sales of molybdenum produced at the North America copper mines.

Our consolidated copper production and sales volumes from the North America copper mines in 2024 were below 2023 volumes, primarily reflecting lower ore grades and operating rates, partly offset by leach recovery initiatives.

North America copper sales are estimated to approximate 1.4 billion pounds in 2025. Refer to “Outlook” for projected molybdenum sales volumes.

Unit Net Cash Costs. We believe unit net cash costs per pound of copper is a measure that provides investors with information about the cash-generating capacity of our mining operations expressed on a basis relating to the primary metal product for our respective operations. We use this measure for the same purpose and for monitoring operating performance by our mining operations. This information differs from measures of performance determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with U.S. GAAP. This measure is presented by other metals mining companies, although our measure may not be comparable to similarly titled measures reported by other companies.


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Gross Profit per Pound of Copper and Molybdenum
The following table summarizes unit net cash costs and gross profit per pound at our North America copper mines for the two years ended December 31, 2024. Refer to “Product Revenues and Production Costs” for an explanation of the “by-product” and “co-product” methods and a reconciliation of unit net cash costs per pound to production and delivery costs applicable to sales reported in our consolidated financial statements.
 20242023
 By-Co-Product MethodBy-Co-Product Method
Product
Method		Copper
Molyb-
denuma
Product
Method		Copper
Molyb-
denuma
Revenues, excluding adjustments$4.29 $4.29 $20.13 $3.93 $3.93 $23.38 
Site production and delivery, before net noncash      
and other costs shown below3.46 3.10 16.20 3.00 2.65 17.63 
By-product credits(0.48)— — (0.49)— — 
Treatment charges0.13 0.12 — 0.12 0.12 — 
Unit net cash costs3.11 3.22 16.20 2.63 2.77 17.63 
DD&A0.34 0.31 1.19 0.30 0.27 1.30 
Noncash and other costs, net0.19 
b
0.18 0.36 0.18 
b
0.16 0.77 
Total unit costs3.64 3.71 17.75 3.11 3.20 19.70 
Revenue adjustments, primarily for pricing on prior period open sales— — — 0.01 0.01 — 
Gross profit per pound$0.65 $0.58 $2.38 $0.83 $0.74 $3.68 
Copper sales (millions of recoverable pounds)1,263 1,263  1,367 1,367  
Molybdenum sales (millions of recoverable pounds)a
  30   30 
a.Reflects sales of molybdenum produced by certain of the North America copper mines to our molybdenum sales company at market-based pricing.
b.Includes charges totaling $0.05 per pound of copper in 2024 and $0.08 per pound of copper in 2023 for feasibility and optimization studies. Also, includes charges totaling $0.05 per pound of copper in 2024 and $0.01 per pound of copper in 2023 for metals inventory adjustments.

Our North America copper mines have varying cost structures because of differences in ore grades and characteristics, processing costs, by-product credits and other factors. Average unit net cash costs (net of by-product credits) for the North America copper mines of $3.11 per pound of copper in 2024 were higher than average unit net cash costs of $2.63 per pound of copper in 2023, primarily reflecting lower copper volumes and higher mining and labor costs.

Because certain assets are depreciated on a straight-line basis, North America’s average unit depreciation rate may vary with asset additions and the level of copper production and sales.

Revenue adjustments primarily result from changes in prices on provisionally priced copper sales recognized in prior periods. Refer to “Consolidated Results – Revenues” for further discussion of adjustments to prior period provisionally priced copper sales.

Average unit net cash costs (net of by-product credits) for the North America copper mines are expected to approximate $3.00 per pound of copper for the year 2025, based on achievement of current sales volume and cost estimates and assuming an average price of $20.00 per pound of molybdenum. North America’s average unit net cash costs for the year 2025 would change by approximately $0.05 per pound for each $2 per pound change in the average price of molybdenum.

South America
We manage two copper operations in South America – Cerro Verde in Peru (in which we own a 55.08% interest) and El Abra in Chile (in which we own a 51% interest), which are consolidated in our financial statements.

In September 2024, we purchased 5.3 million shares of Cerro Verde common stock for $210 million, increasing our ownership interest in Cerro Verde to 55.08% from 53.56%.

South America operations includes open-pit mining, sulfide-ore concentrating, leaching and SX/EW facilities. Production from our South America operations is sold as copper concentrate or cathode under long-term contracts.
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Our South America operations also sell a portion of their copper concentrate production to Atlantic Copper. In addition to copper, the Cerro Verde mine produces molybdenum concentrate and silver.

Development Activities. Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of risks associated with development projects.

At the El Abra operations in Chile, we have completed substantial drilling and evaluations to define a large sulfide resource that would support a potential major mill project similar to the large-scale concentrator at Cerro Verde. We are preparing data for a potential submission of an environmental impact statement by year-end 2025, subject to ongoing stakeholder engagement and economic evaluations. Preliminary estimates, which remain under review, indicate that the project economics would be supported using an incentive copper price of less than $4.00 per pound. The decision of whether to proceed and timing of the potential project will take into account overall copper market conditions, required permitting and other factors.

Operating Data. Following is summary consolidated operating data for our South America operations for the years ended December 31.
 2024 2023
Copper (millions of recoverable pounds)
  
Production 1,168 1,202 
Sales 1,177 1,200 
Average realized price per pound$4.16 $3.82 
Molybdenum (millions of recoverable pounds)
  
Productiona
20 22 
Leach operations  
Leach ore placed in stockpiles (metric tons per day)164,300 191,200 
Average copper ore grade (%)0.42 0.35 
Copper production (millions of recoverable pounds)295 317 
Mill operations  
Ore milled (metric tons per day)415,500 417,400 

Average ore grade (%):
Copper0.33 0.34 
Molybdenum0.01 0.01 
Copper recovery rate (%)83.6 81.3 
Copper production (millions of recoverable pounds)873 885 
a.Refer to “Consolidated Results” for our consolidated molybdenum sales volumes, which include sales of molybdenum produced at Cerro Verde.

Our consolidated copper production and sales volumes from our South America operations in 2024 were slightly lower than 2023 volumes, primarily reflecting lower operating rates, offset by higher ore grades.

South America copper sales volumes are expected to approximate 1.1 billion in 2025 as a result of slightly lower expected ore grades. Refer to “Outlook” for projected molybdenum sales volumes.

Unit Net Cash Costs. We believe unit net cash costs per pound of copper is a measure that provides investors with information about the cash-generating capacity of our mining operations expressed on a basis relating to the primary metal product for our respective operations. We use this measure for the same purpose and for monitoring operating performance by our mining operations. This information differs from measures of performance determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with U.S. GAAP. This measure is presented by other metals mining companies, although our measure may not be comparable to similarly titled measures reported by other companies.


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Gross Profit per Pound of Copper
The following table summarizes unit net cash costs and gross profit per pound of copper at our South America operations for the two years ended December 31, 2024. Unit net cash costs per pound of copper are reflected under the by-product and co-product methods as the South America operations also had sales of molybdenum and silver. Refer to “Product Revenues and Production Costs” for an explanation of the “by-product” and “co-product” methods and a reconciliation of unit net cash costs per pound to production and delivery costs applicable to sales reported in our consolidated financial statements.
 20242023
By-Product
Method		Co-Product
Method		By-Product
Method		Co-Product
Method
Revenues, excluding adjustments$4.16 $4.16 $3.82 $3.82 
Site production and delivery, before net noncash    
and other costs shown below2.63 2.43 2.57 2.34 
By-product credits(0.34)— (0.39)— 
Treatment charges0.16 0.16 0.19 0.19 
Royalty on metals0.01 0.01 0.01 0.01 
Unit net cash costs2.46 2.60 2.38 2.54 
DD&A0.38 0.35 0.38 0.35 
Noncash and other costs, net0.08 
a
0.07 0.08 
a
0.07 
Total unit costs2.92 3.02 2.84 2.96 
Revenue adjustments, primarily for pricing on
prior period open sales0.03 0.03 0.06 0.06 
Gross profit per pound$1.27 $1.17 $1.04 $0.92 
Copper sales (millions of recoverable pounds)1,177 1,177 1,200 1,200 
a.Includes $0.05 per pound of copper in 2024 and $0.04 per pound of copper in 2023 for feasibility and optimization studies.

Our South America operations have varying cost structures because of differences in ore grades and characteristics, processing costs, by-product credits and other factors. Average unit net cash costs (net of by-product credits) for South America operations of $2.46 per pound of copper in 2024 were higher than average unit net cash costs of $2.38 per pound in 2023, primarily reflecting charges totaling $97 million ($0.08 per pound of copper) associated with nonrecurring labor-related charges at Cerro Verde associated with new multi-year CLAs with its two unions and lower by-product credits.

Revenues from Cerro Verde’s copper concentrate sales are recorded net of treatment charges, which will vary with Cerro Verde’s sales volumes and the price of copper.

Because certain assets are depreciated on a straight-line basis, South America’s unit depreciation rate may vary with asset additions and the level of copper production and sales.

Revenue adjustments primarily result from changes in prices on provisionally priced copper sales recognized in prior periods. Refer to “Consolidated Results – Revenues” for further discussion of adjustments to prior period provisionally priced copper sales.

Average unit net cash costs (net of by-product credits) for South America operations are expected to approximate $2.50 per pound of copper for the year 2025, based on achievement of current sales volume and cost estimates and assuming an average price of $20.00 per pound of molybdenum.

Indonesia
PT-FI operates one of the world’s largest copper and gold mines at the Grasberg minerals district in Central Papua, Indonesia. PT-FI produces copper concentrate that contains significant quantities of gold and silver. We have a 48.76% ownership interest in PT-FI and manage its operations. PT-FI's results are consolidated in our financial statements. Once the full ramp-up of the new downstream processing facilities is achieved, PT-FI will be a fully integrated producer of refined copper and gold.

Concentrate Exports. Current regulations in Indonesia prohibit exports of copper concentrate as of January 1, 2025. Pursuant to the terms of its special mining business license (IUPK) regarding force majeure events, PT-FI has requested approval from the Indonesia government to permit the export of copper concentrate in 2025 until the
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required repairs of its new smelter following the October 2024 fire incident (see below for further discussion) and full ramp-up are complete. Based on discussions with the Indonesia government, PT-FI expects to re-commence exports of copper concentrate during first-quarter 2025, and pursuant to current regulations, would be required to pay a 7.5% export duty on copper concentrate exports during 2025.

Refer to Notes 10 and 11 for further discussion of Indonesia regulatory matters, including its IUPK, export proceeds and export duties.

Long-Term Mining Rights. Pursuant to regulations issued during 2024, PT-FI is eligible to apply for an extension of its mining rights beyond 2041, provided certain conditions are met, including ownership of integrated downstream facilities that have entered the operational stage; domestic ownership of at least 51% and agreement with a state-owned enterprise for an additional 10% ownership; and commitments for additional exploration and increases in refining capacity, each as approved by the Ministry of Energy and Mineral Resources. Application for extension may be submitted at any time up to one year prior to the expiration of PT-FI’s IUPK. PT-FI expects to apply for an extension during 2025, pending agreement with MIND ID on a purchase and sale agreement for the transfer in 2041 of an additional 10% interest in PT-FI.

An extension would enable continuity of large-scale operations for the benefit of all stakeholders and provide growth options through additional resource development opportunities in the highly attractive Grasberg minerals district.

Operating and Development Activities. Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of risks associated with development projects.

Over a multi-year investment period, PT-FI has successfully commissioned three large-scale underground mines in the Grasberg minerals district (Grasberg Block Cave, Deep Mill Level Zone (DMLZ) and Big Gossan). Milling rates for ore from these underground mines averaged 208,400 metric tons of ore per day in 2024 and 198,300 metric tons of ore per day in 2023. In December 2024, PT-FI completed construction of a new copper cleaner circuit, a mill recovery project to enhance recoveries and optimize concentrate production, with commissioning underway.

Kucing Liar. Long-term mine development activities are ongoing for PT-FI’s Kucing Liar deposit in the Grasberg minerals district. Kucing Liar is expected to produce over 7 billion pounds of copper and 6 million ounces of gold between 2029 and the end of 2041, and an extension of PT-FI’s operating rights beyond 2041 would extend the life of the project. Development activities commenced in 2022 and are expected to continue over an approximate 10-year timeframe. Capital investments for Kucing Liar are estimated to total $4 billion over the next seven to eight years (averaging approximately $0.5 billion per annum). Approximately $0.6 billion has been incurred through December 31, 2024. At full operating rates, annual production from Kucing Liar is expected to approximate 560 million pounds of copper and 520 thousand ounces of gold, providing PT-FI with sustained long-term, large-scale and low-cost production. Kucing Liar will benefit from substantial shared infrastructure and PT-FI’s experience and long-term success in block-cave mining.

Natural Gas Facilities. PT-FI plans to transition its existing energy source from coal to natural gas, which would meaningfully reduce PT-FI’s Scope 1 greenhouse gas emissions at the Grasberg minerals district. The majority of PT-FI’s planned investments in a new gas-fired combined cycle facility are expected to be incurred over the next three years, at a cost of approximately $1 billion, which represents an incremental cost of $0.4 billion compared to previously planned investments to refurbish the existing coal units. Once complete, PT-FI’s dual-fuel power plant and the new gas-fired combined cycle facility will be fueled by natural gas, supplied by a floating liquefied natural gas storage and regassification unit.

Downstream Processing Facilities.
New Smelter. Construction of the new greenfield smelter in Eastern Java, Indonesia was completed during 2024. In October 2024, during start-up activities, a fire occurred that required a temporary suspension of smelting operations to complete repairs. Procurement of long-lead items is advanced and repairs are scheduled to be completed by mid-2025, and PT-FI expects ramp-up to full capacity to be achieved by year-end 2025. PT-FI expects restoration, repair and replacement costs to approximate $100 million, which are expected to be mostly offset through recovery under construction insurance programs.
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PMR. As part of start-up activities, PT-FI commenced gold production at its new PMR in December 2024. The facility has capacity to refine all precious metals from PT-FI’s new smelter as well as from PT Smelting, PT-FI’s 66%-owned smelter and refinery in Gresik, Indonesia.

Refer to “Smelting and Refining” and Note 2 for further discussion of PT Smelting.

Operating Data. Following is summary consolidated operating data for Indonesia operations for the years ended December 31.
 2024 2023
Operating Data  
Copper (millions of recoverable pounds)
  
Production 1,800 1,660 
Sales1,632 1,525 
Average realized price per pound$4.19 $3.81 
Gold (thousands of recoverable ounces)
  
Production 1,861 1,978 
Sales1,817 1,697 
Average realized price per ounce$2,418 $1,972 
Ore extracted and milled (metric tons per day):  
Grasberg Block Cave underground mine133,800 117,300 
DMLZ underground mine64,900 75,900 
Big Gossan underground mine8,000 7,900 
Other adjustments1,700 (2,800)
Total208,400 198,300 
Average ore grade:  
Copper (%)1.27 1.22 
Gold (grams per metric ton)1.00 1.12 
Recovery rates (%):
Copper88.4 89.7 
Gold76.9 77.9 

Higher consolidated copper and gold sales volumes in 2024, compared with 2023, primarily reflected higher mining and milling rates, higher copper ore grades and the timing of shipments.

PT-FI’s consolidated copper production volumes for 2024 exceeded sales volumes, reflecting an increase in concentrate inventory held at PT-FI’s new downstream processing facilities expected to be sold as refined metal in the second half of 2025. PT-FI’s consolidated copper and gold production volumes for 2023 exceeded sales volumes, reflecting the deferral of sales recognition related to the PT Smelting tolling arrangement (as discussed below and in Note 2).

Consolidated sales volumes from PT-FI are expected to approximate 1.55 billion pounds of copper and 1.6 million ounces of gold in 2025. PT-FI’s projected sales volumes in 2025 reflect reduced operating rates associated with two major maintenance projects in its concentrating facilities. Projected sales volumes are dependent on operational performance; Indonesia regulatory approval to export copper concentrate until repairs and full ramp-up of PT-FI’s new smelter are complete; weather-related conditions; and other factors detailed in the “Cautionary Statement” below.

Unit Net Cash (Credits) Costs. We believe unit net cash (credits) costs per pound of copper is a measure that provides investors with information about the cash-generating capacity of our mining operations expressed on a basis relating to the primary metal product for our respective operations. We use this measure for the same purpose and for monitoring operating performance by our mining operations. This information differs from measures of performance determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with U.S. GAAP. This measure is presented by other metals mining companies, although our measure may not be comparable to similarly titled measures reported by other companies.
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Gross Profit per Pound of Copper and per Ounce of Gold
The following table summarizes the unit net cash (credits) costs and gross profit per pound of copper and per ounce of gold at our Indonesia mining operations for the two years ended December 31, 2024. Refer to “Product Revenues and Production Costs” for an explanation of “by-product” and “co-product” methods and a reconciliation of unit net cash costs per pound to production and delivery costs applicable to sales reported in our consolidated financial statements.
 20242023
 By-
Product		Co-Product MethodBy-
Product		Co-Product Method
MethodCopperGoldMethodCopperGold
Revenues, excluding adjustments$4.19 $4.19 $2,418 $3.81 $3.81 $1,972 
Site production and delivery, before net noncash      
and other costs shown below1.64 0.98 566 1.62 1.01 522 
Gold, silver and other by-product credits(2.82)— — (2.30)— — 
Treatment charges0.35 0.21 120 0.35 0.22 114 
Export duties0.28 0.17 96 0.21 0.13 69 
Royalty on metals0.27 0.16 92 0.22 0.14 71 
Unit net cash (credits) costs (0.28)1.52 874 0.10 1.50 776 
DD&A0.73 0.44 252 0.68 0.42 218 
Noncash and other costs, net0.22 
a
0.13 77 0.01 
b
0.01 5 
Total unit costs0.67 2.09 1,203 0.79 1.93 999 
Revenue adjustments, primarily for pricing on
prior period open sales0.01 0.01 (2)0.08 0.07 9 
PT Smelting intercompany profit — — — 0.07 0.05 24 
Gross profit per pound/ounce$3.53 $2.11 $1,213 $3.17 $2.00 $1,006 
Copper sales (millions of recoverable pounds)1,632 1,632  1,525 1,525  
Gold sales (thousands of recoverable ounces)  1,817   1,697 
a.Includes charges of $0.09 per pound of copper associated with ARO adjustments, $0.08 per pound of copper for operational readiness and start-up costs associated with PT-FI’s new downstream processing facilities, $0.02 per pound of copper for amounts capitalized in prior years associated with construction of PT-FI’s new downstream processing facilities and $0.02 per pound of copper for feasibility and optimization studies.
b.Includes credits of $0.07 per pound of copper associated with ARO adjustments, and charges of $0.04 per pound of copper associated with an administrative fine and $0.02 per pound of copper for feasibility and optimization studies.

A significant portion of PT-FI’s costs are fixed and unit costs vary depending on volumes and other factors. PT-FI’s unit net cash credits (including gold, silver and other by-product credits) of $0.28 per pound of copper in 2024 was favorable compared to the unit net cash costs (net of gold, silver and other by-product credits) of $0.10 per pound of copper in 2023, primarily reflecting higher gold credits and higher copper volumes.

Treatment charges vary with the volume of metals sold and the price of copper, and royalties vary with the volume of metals sold and the prices of copper and gold. PT-FI royalties totaled $433 million in 2024 and $338 million in 2023.

Export duties totaled $457 million in 2024 and $324 million in 2023. Refer to Note 11 for further discussion of PT-FI’s export duties.

Because certain assets are depreciated on a straight-line basis, PT-FI’s unit depreciation rate may vary with asset additions and the level of copper volumes and changes in copper and gold inventory.

Revenue adjustments primarily result from changes in prices on provisionally priced copper sales recognized in prior periods. Refer to “Consolidated Results – Revenues” for further discussion of adjustments to prior period provisionally priced copper sales.

As discussed in Note 2, beginning in 2023, PT-FI’s commercial arrangement with PT Smelting changed from a copper concentrate sales agreement to a tolling arrangement and there are no further sales from PT-FI to PT Smelting. PT Smelting’s intercompany profit for 2023 represents the change in the deferral of PT-FI’s profit on prior sales to PT Smelting.
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Average unit net cash credits (including gold, silver and other by-product credits) for PT-FI are expected to approximate $0.27 per pound of copper for the year 2025, based on achievement of current sales volumes (including estimates for copper concentrate exports) and cost estimates and assuming an average price of $2,700 per ounce of gold. PT-FI’s average unit net cash costs for the year 2025 would change by approximately $0.09 per pound of copper for each $100 per ounce change in the average price of gold.

PT-FI’s projected sales volumes and unit net cash costs for the year 2025 are dependent on operational performance; Indonesia regulatory approval to export copper concentrate until repairs and full ramp-up of PT-FI’s new smelter are complete; weather-related conditions; timing of shipments; and other factors. Refer to “Cautionary Statement” below, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of factors that could cause results to differ materially from projections.

Molybdenum Mines
We operate two wholly owned primary molybdenum operations in Colorado – the Climax open-pit mine and the Henderson underground mine. The Climax and Henderson mines produce high-purity, chemical-grade molybdenum concentrate, which is typically further processed into value-added molybdenum chemical products. The majority of the molybdenum concentrate produced at the Climax and Henderson mines, as well as from our North America copper mines and South America operations, is processed at our conversion facilities.

Operating and Development Activities. Production from the Molybdenum mines totaled 30 million pounds of molybdenum in both 2024 and 2023. Refer to “Consolidated Results” for our consolidated molybdenum operating data, which includes sales of molybdenum produced at our primary molybdenum operations and from our North America copper mines and South America operations. Refer to “Outlook” for projected consolidated molybdenum sales volumes and to “Markets” for a discussion of molybdenum prices.

Unit Net Cash Costs per Pound of Molybdenum. We believe unit net cash costs per pound of molybdenum is a measure that provides investors with information about the cash-generating capacity of our mining operations expressed on a basis relating to the primary metal product for our respective operations. We use this measure for the same purpose and for monitoring operating performance by our mining operations. This information differs from measures of performance determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with U.S. GAAP. This measure is presented by other metals mining companies, although our measure may not be comparable to similarly titled measures reported by other companies.

Average unit net cash costs for our Molybdenum mines of $17.89 per pound of molybdenum in 2024 were higher than $15.13 per pound of molybdenum in 2023, primarily reflecting contract labor transition costs. Average unit net cash costs for the Molybdenum mines are expected to approximate $15.20 per pound of molybdenum for the year 2025, based on achievement of current sales volumes and cost estimates. Refer to “Product Revenues and Production Costs” for a reconciliation of unit net cash costs per pound to production and delivery costs applicable to sales reported in our consolidated financial statements.

Smelting and Refining
Through our downstream integration, we are able to assure placement of a significant portion of our copper concentrate production. PT-FI wholly owns and operates its new downstream facilities in Eastern Java, Indonesia, and has a 66% ownership interest in PT Smelting (39.5% prior to June 30, 2024), which is operated by Mitsubishi Materials Corporation (refer to Note 2 for further discussion of PT Smelting). We wholly own and operate the Miami smelter in Arizona, the El Paso refinery in Texas, and Atlantic Copper smelter and refinery in Huelva, Spain.

During 2024, PT-FI completed construction of its new downstream processing facilities. In October 2024, during start-up activities of the new smelter, a fire occurred requiring a temporary suspension of smelting operations to complete repairs (for further discussion refer to “Operations – Indonesia – Downstream Processing Facilities”). The new smelter will smelt and refine copper concentrate from PT-FI and the PMR, which commenced gold production as part of start-up activities in December 2024, will process anode slimes from the new smelter and PT Smelting. Once its new downstream processing facilities are operational, PT-FI’s operations will be fully integrated and treatment charges reflecting the cost of smelting and refining operations will be recorded in production and delivery costs. PT-FI recorded charges for operational readiness and startup costs associated with the new downstream processing facilities totaling $133 million in 2024. We estimate that operational readiness and startup costs associated with the new downstream processing facilities will approximate $120 million for the year 2025.
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The Miami smelter has been operating for over 100 years and has been upgraded numerous times during that period to implement new technologies, improve production and comply with air quality requirements. Major maintenance turnarounds are anticipated to occur approximately every three to four years for the Miami smelter. We performed a major maintenance turnaround for the Miami smelter during 2021 and the next major maintenance turnaround is scheduled for mid-year 2025, for which we expect to incur maintenance charges and idle facility costs of approximately $85 million.

Atlantic Copper smelts and refines copper concentrate and markets refined copper and precious metals in slimes. During the year 2024, Atlantic Copper’s copper concentrate purchases included 30% from our copper mining operations and 70% from third parties. Atlantic Copper’s treatment charges, which consist of a base rate per pound of copper and per ounce of gold, are generally fixed and represent a cost to our mining operations and income to Atlantic Copper (i.e., higher treatment charges benefit our Atlantic Copper operations). Our North America copper mines are less significantly affected by changes in treatment charges because these operations are largely integrated with our Miami smelter and El Paso refinery.

We defer recognizing profits on sales from our mining operations to Atlantic Copper until final sales to third parties occur. Changes in these deferrals attributable to variability in intercompany volumes resulted in net additions (reductions) to operating income totaling $21 million ($(3) million to net income attributable to common stock) in 2024 and $64 million ($37 million to net income attributable to common stock) in 2023. Our net deferred profits on our inventories at Atlantic Copper to be recognized in future periods’ operating income totaled $181 million ($60 million to net income attributable to common stock) at December 31, 2024. Quarterly variations in ore grades, the timing of intercompany shipments and changes in product prices will result in variability in our net deferred profits and quarterly earnings.

In May 2024, the U.S. Environmental Protection Agency (EPA) amended its rule establishing standards for hazardous air pollutant emissions from primary copper smelters. This final rule will impact our Miami, Arizona smelter operations, which process a significant portion of the copper concentrate produced by our North America copper mines. We are evaluating processes and equipment modifications and the costs involved, which could be significant in connection with the revised rule requirements. Our appeal of EPA’s final rule to the Court of Appeals for the District of Columbia Circuit is suspended, pending resolution of several petitions for reconsideration to EPA filed by us and other parties. Refer to “Governmental Regulations – Environmental Matters” in Items 1 and 2. “Business and Properties” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for additional information on new and revised environmental regulatory requirements that may result in substantial increased costs for our business.

CAPITAL RESOURCES AND LIQUIDITY

Our consolidated operating cash flows vary with sales volumes; prices realized from copper, gold and molybdenum sales; production costs; income taxes; other working capital changes; and other factors. See “Consolidated Results,” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of our energy requirements and related costs.

We remain focused on managing costs efficiently and continue to advance several important value-enhancing initiatives. We believe the actions we have taken in recent years to build a solid balance sheet, successfully expand low-cost operations and maintain flexible organic growth options while maintaining sufficient liquidity, will allow us to continue to execute our business plans in a prudent manner during periods of economic uncertainty while preserving substantial future asset values. We closely monitor market conditions and will adjust our operating plans to protect liquidity and preserve our asset values, if necessary. We expect to maintain a strong balance sheet and liquidity position as we focus on building long-term value in our business, executing our operating plans safely, responsibly and efficiently, and prudently managing costs and capital expenditures.

Based on current sales volume, cost and metal price estimates and planned capital expenditures discussed in “Outlook,” our available cash and cash equivalents plus our projected consolidated operating cash flows of $6.2 billion for the year 2025 exceed our expected consolidated capital expenditures of $5.0 billion. We have cash on hand and the financial flexibility to fund capital expenditures and our other cash requirements for the next twelve months, including noncontrolling interest distributions, income tax payments, current common stock dividends (base and variable) and any share or debt repurchases. Planned capital expenditures for major mining projects over the next few years are primarily associated with underground mine development in the Grasberg minerals district and
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potential expansion projects in North America. At December 31, 2024, we had $3.9 billion of consolidated cash and cash equivalents ($4.7 billion including $0.7 billion of current restricted cash associated with a portion of PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks), and FCX, PT-FI and Cerro Verde have $3.0 billion, $1.5 billion and $350 million, respectively, available under their revolving credit facilities.

Financial Policy. Our financial policy is aligned with our strategic objectives of maintaining a solid balance sheet, providing cash returns to shareholders and advancing opportunities for future growth. The policy includes a base dividend and a performance-based payout framework, whereby up to 50% of available cash flows generated after planned capital spending and distributions to noncontrolling interest would be allocated to shareholder returns and the balance to debt reduction and investments in value enhancing growth projects, subject to us maintaining our net debt at a level not to exceed the net debt target of $3.0 billion to $4.0 billion (excluding debt for PT-FI’s new downstream processing facilities). Our Board reviews the structure of the performance-based payout framework at least annually.

At December 31, 2024, our net debt, excluding $3.2 billion of debt for PT-FI’s new downstream processing facilities, totaled $1.06 billion. Refer to “Net Debt” for further discussion.

On December 18, 2024, our Board declared cash dividends totaling $0.15 per share on our common stock (including a $0.075 per share quarterly base cash dividend and a $0.075 per share quarterly variable, performance-based cash dividend), which was paid on February 3, 2025, to shareholders of record as of January 15, 2025. The declaration and payment of dividends (base or variable) are at the discretion of our Board and will depend on our financial results, cash requirements, global economic conditions and other factors deemed relevant by our Board.

During 2024 we acquired 1.2 million shares of our common stock for a total cost of $59 million ($50.48 average cost per share) bringing total purchases under our $5.0 billion share repurchase program to 49.0 million shares for a cost of $1.9 billion ($38.64 average cost per share). The timing and amount of share repurchases are at the discretion of management and will depend on a variety of factors. The share repurchase program may be modified, increased, suspended or terminated at any time at the Board’s discretion.

Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, and “Cautionary Statement” below for further discussion.

Cash
Following is a summary of the U.S. and international components of consolidated cash and cash equivalents available to the parent company, net of noncontrolling interests’ share and withholding taxes, at December 31, 2024 (in billions):
Cash at domestic companies$1.5 
Cash at international operations2.4 
a
Total consolidated cash and cash equivalents3.9 
Noncontrolling interests’ share(1.1)
Cash, net of noncontrolling interests’ share2.8 
Withholding taxes(0.1)

Net cash available$2.7 
a.Excludes $0.7 billion of current restricted cash associated with a portion of PT-FI's export proceeds required to be temporarily deposited in Indonesia banks for 90 days in accordance with a regulation issued by the Indonesia government (refer to Note 10).

Cash held at our international operations is generally used to support our foreign operations’ capital expenditures, operating expenses, debt repayments, working capital or other cash needs. Management believes that sufficient liquidity is available in the U.S. from cash balances and availability from our revolving credit facility. We have not elected to permanently reinvest earnings from our foreign subsidiaries, and we have recorded deferred tax liabilities for foreign earnings that are available to be repatriated to the U.S. From time to time, our foreign subsidiaries distribute earnings to the U.S. through dividends that are subject to applicable withholding taxes and noncontrolling interests’ share. See Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of our holding company structure and the potential impact of changes in tax laws.


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Debt
At December 31, 2024, consolidated debt totaled $8.9 billion, with a weighted-average interest rate of 5.2%. Refer to “Interest Rate Risk” for further discussion of our fixed- and variable-rate debt.

In November 2024, we repaid $0.7 billion in scheduled senior note maturities using cash on hand and our next senior note maturities are in 2027. Our total debt has an average remaining duration of approximately 10 years.

At December 31, 2024, we had no borrowings and $7 million in letters of credit issued under our $3.0 billion revolving credit facility, PT-FI had $250 million in borrowings outstanding under its $1.75 billion revolving credit facility and Cerro Verde had no borrowings under its $350 million revolving credit facility. Refer to Note 6 for further discussion.

Operating Activities
We generated consolidated operating cash flows of $7.2 billion in 2024 and $5.3 billion in 2023. Higher operating cash flows in 2024, compared with 2023, primarily reflect higher average realized copper and gold prices and higher gold sales volumes, as well as working capital changes related to the timing of approval of PT-FI’s permitted copper concentrate export quota for 2024 and routine timing related impacts associated with payments to suppliers.

Investing Activities
Capital Expenditures. Capital expenditures, including capitalized interest, totaled $4.8 billion in 2024 and 2023, including amounts for major mining projects ($2.1 billion in 2024 and $1.8 billion in 2023) primarily associated with the underground development activities in the Grasberg minerals district, and for PT-FI’s new downstream processing facilities ($1.2 billion in 2024 and $1.7 billion in 2023).

Refer to “Outlook” for further discussion of projected capital expenditures for 2025.

Acquisition of Additional Ownership Interest in Cerro Verde. In September 2024, we purchased 5.3 million shares of Cerro Verde common stock for a total cost of $210 million, increasing our ownership interest in Cerro Verde to 55.08% from 53.56%.

Loans to PT Smelting for Expansion. PT-FI made loans to PT Smelting totaling $28 million in 2024 and $129 million in 2023 to fund PT Smelting’s expansion project. Refer to Note 2 for further discussion.

Financing Activities
Debt Transactions. Net repayments of debt totaled $0.5 billion in 2024, including the repayment of our 4.55% Senior Notes that matured in November 2024 totaling $730 million, partly offset by $250 million in borrowings under the PT-FI revolving credit facility that were used to fund capital expenditures for PT-FI’s new downstream processing facilities.

Net repayments of debt totaled $1.2 billion in 2023, including the repayment of our 3.875% Senior Notes that matured in March 2023 totaling $996 million and open-market purchases of senior notes totaling $221 million.

Cash Dividends on Common Stock. We paid cash dividends on our common stock totaling $0.9 billion in 2024 and in 2023. The declaration and payment of dividends (base or variable) is at the discretion of our Board and will depend on our financial results, cash requirements, global economic conditions and other factors deemed relevant by our Board. Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, and “Cautionary Statement” below.

Cash Dividends and Distributions Paid to Noncontrolling Interests. Cash dividends and distributions paid to noncontrolling interests at our international operations totaled $1.8 billion (including $1.4 billion paid to PT-FI’s noncontrolling shareholders) in 2024 and $0.6 billion (including $0.3 billion paid to PT-FI’s noncontrolling shareholders) in 2023. Cash dividends and distributions to noncontrolling interests vary based on the operating results and cash requirements of our consolidated subsidiaries.

Treasury Stock Purchases. In 2024, we acquired 1.2 million shares of our common stock for a total cost of $59 million ($50.48 average cost per share) under the share repurchase program. There were no shares acquired under the program in 2023. As of February 14, 2025, $3.1 billion remains available under the share repurchase program. Refer to Note 8 for further discussion.

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Contributions from Noncontrolling Interests. We received equity contributions totaling $50.0 million in 2023 from MIND ID for its share of capital spending on the underground mine development projects in the Grasberg minerals district.

CONTINGENCIES

Environmental Obligations and AROs
Refer to Note 10 and “Critical Accounting Estimates,” and Items 1. and 2. “Business and Properties” and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further information about contingencies associated with environmental matters and AROs.

For 2025, we expect to incur approximately $0.6 billion of aggregate environmental capital expenditures and other environmental costs and $0.2 billion in aggregate ARO expenditures.

Leases
Refer to Note 11, and Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for information about lease commitments.

Litigation and Other Contingencies
Refer to Note 10, and Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of contingencies associated with legal proceedings and other matters, including tax and Indonesia regulatory matters.

DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk
Our 2024 consolidated revenues from our copper mining operations include the sale of copper concentrate, copper cathode, copper rod, gold, silver, molybdenum and other metals, the sale of molybdenum in various forms by our molybdenum operations, and the sale of copper cathode, copper anode and gold in anode and slimes by Atlantic Copper. Our financial results will vary with fluctuations in the market prices of the commodities we produce, primarily copper and gold, and to a lesser extent molybdenum. For projected sensitivities of our operating cash flow to changes in commodity prices, refer to “Outlook.” World market prices for these commodities have fluctuated historically and are affected by numerous factors beyond our control. Refer to Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024, for further discussion of financial risks associated with fluctuations in the market prices of the commodities we sell.

During 2024, our mined copper was sold 45% in concentrate, 34% as cathode and 21% as rod. All of our copper concentrate and some cathode sales contracts provide final copper pricing in a specified future month (generally one to four months from the shipment date) based primarily on quoted LME monthly average copper settlement prices. We receive market prices based on prices in the specified future period, which results in price fluctuations recorded through revenues until the date of settlement. We record revenues and invoice customers at the time of shipment based on then-current LME prices, which results in an embedded derivative on our provisionally priced concentrate and cathode sales that is adjusted to fair value through earnings each period, using the period-end forward prices, until final pricing on the date of settlement. To the extent final prices are higher or lower than what was recorded on a provisional basis, an increase or decrease to revenues is recorded each reporting period until the date of final pricing. Accordingly, in times of rising copper prices, our revenues benefit from adjustments to the final pricing of provisionally priced sales pursuant to contracts entered into in prior periods; in times of falling copper prices, the opposite occurs.


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Following are the favorable impacts of net adjustments to the prior years’ provisionally priced copper sales for the years ended December 31 (in millions, except per share amounts):
 2024 2023 
Revenues$28 $183 
Net income attributable to common stock$9 $62 
Net income per share attributable to common stock$0.01 $0.04 

At December 31, 2024, we had provisionally priced copper sales at our copper mining operations totaling 133 million pounds of copper (net of intercompany sales and noncontrolling interests) recorded at an average price of $3.96 per pound, subject to final pricing over the next several months. We estimate that each $0.05 change in the price realized from the December 31, 2024, provisional price recorded would have an approximate $12 million effect on 2025 revenues ($4 million to net income attributable to common stock). The LME copper settlement price closed at $4.25 per pound on February 13, 2025.

Foreign Currency Exchange Risk
The functional currency for most of our operations is the U.S. dollar. Substantially all of our revenues and a significant portion of our costs are denominated in U.S. dollars; however, some costs and certain asset and liability accounts are denominated in local currencies, including the Indonesia rupiah, Peruvian sol, Chilean peso and euro. We recognized foreign currency translation gains on balances denominated in foreign currencies totaling $17 million in 2024 and $20 million in 2023. Generally, our operating results are positively affected when the U.S. dollar strengthens in relation to those foreign currencies and are adversely affected when the U.S. dollar weakens in relation to those foreign currencies.

Following is a summary of estimated annual payments and the impact of changes in foreign currency rates on our annual operating costs:
Exchange Rate per $1
at December 31,		Estimated Annual Payments
10% Change in
Exchange Rate
(in millions of U.S. dollars)a
 20242023(in local currency)
(in millions of U.S. dollars)b
IncreaseDecrease
Indonesia      
Rupiah16,081 15,339 17.9 trillion$1,113 $(101)$124 
Australian dollar1.61 1.47 283 million$175 $(16)$19 
South America  
Peruvian sol3.77 3.71 2.1 billion$555 $(50)$62 
Chilean peso996 877 252 billion$253 $(23)$28 
Spain  
Euro0.96 0.91 164 million$170 $(15)$19 
a.Reflects the estimated impact on annual operating costs assuming a 10% increase or decrease in the exchange rate reported at December 31, 2024.
b.Based on exchange rates at December 31, 2024.

Interest Rate Risk
At December 31, 2024, we had total future debt maturities based on principal amounts of $9.0 billion, of which 97% was fixed-rate debt. The table below presents average interest rates for our scheduled maturities of principal for our outstanding debt and the related fair values at December 31, 2024 (in millions, except percentages):
 20252026202720282029ThereafterFair Value
Fixed-rate debt$10 $5 $1,321 $923 $477 $5,985 $8,526 
Average interest rate0.7 %1.7 %5.0 %4.2 %5.2 %5.4 %5.2 %
Variable-rate debt$31 $— $— $250 $— $— $281 
Average interest rate3.4 %— %— %6.0 %— %— %5.7 %

NEW ACCOUNTING STANDARDS

Refer to Note 1 for discussion of recently issued accounting standards and their projected impact on our future financial statements and disclosures.
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NET DEBT

We believe that net debt provides investors with information related to the performance-based payout framework in our financial policy, which requires us to maintain our net debt at a level not to exceed the net debt target of $3 billion to $4 billion, excluding debt for PT-FI’s new downstream processing facilities. We define net debt as consolidated debt less (i) consolidated cash and cash equivalents and (ii) current restricted cash associated with PT-FI’s export proceeds. This information differs from consolidated debt determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for consolidated debt determined in accordance with U.S. GAAP. Our net debt, which may not be comparable to similarly titled measures reported by other companies, follows (in millions):
As of December 31, 2024
Current portion of debt$41 
Long-term debt, less current portion8,907 
Consolidated debt8,948 
Less: consolidated cash and cash equivalents3,923 
Less: current restricted cash associated with PT-FI’s export proceeds736 
a
FCX net debt4,289 
Less: debt for PT-FI’s new downstream processing facilities3,233 
b
FCX net debt, excluding debt for PT-FI’s new downstream processing facilities$1,056 
a.In accordance with a regulation issued by the Indonesia government, 30% of PT-FI’s export proceeds are being temporarily deposited into Indonesia banks for a period of 90 days before withdrawal and are presented as current restricted cash and cash equivalents in our consolidated balance sheet. As the 90-day holding period is the only restriction on the cash, we have included such amount in the calculation of net debt.
b.Represents PT-FI’s senior notes and $250 million of borrowings under PT-FI’s revolving credit facility.

PRODUCT REVENUES AND PRODUCTION COSTS

Mining Product Revenues and Unit Net Cash Costs (Credits)
We believe unit net cash costs (credits) per pound of copper and molybdenum are measures intended to provide investors with information about the cash-generating capacity of our mining operations expressed on a basis relating to the primary metal product for the respective operations. We use this measure for the same purpose and for monitoring operating performance by our mining operations. This information differs from measures of performance determined in accordance with U.S. GAAP and should not be considered in isolation or as a substitute for measures of performance determined in accordance with U.S. GAAP. These measures are presented by other metals mining companies, although our measures may not be comparable to similarly titled measures reported by other companies.

We present gross profit per pound of copper in the following tables using both a “by-product” method and a “co-product” method. We use the by-product method in our presentation of gross profit per pound of copper because (i) the majority of our revenues are copper revenues, (ii) we mine ore, which contains copper, gold, molybdenum and other metals, (iii) it is not possible to specifically assign all of our costs to revenues from the copper, gold, molybdenum and other metals we produce, and (iv) it is the method used by our management and Board to monitor our operations and to compare mining operations in certain industry publications. In the co-product method presentations, shared costs are allocated to the different products based on their relative revenue values, which will vary to the extent our metals sales volumes and realized prices change.

We show revenue adjustments for prior period open sales as separate line items. Because these adjustments do not result from current period sales, these amounts have been reflected separately from revenues on current period sales. Noncash and other costs, net which are removed from site production and delivery costs in the calculation of unit net cash costs, consist of items such as ARO accretion and other adjustments, inventory write-offs and adjustments, stock-based compensation costs, long-lived asset impairments, idle facility costs, feasibility and optimization study costs, operational readiness and startup costs, restructuring and/or unusual charges. As discussed above, gold, molybdenum and other metal revenues at copper mines are reflected as credits against site production and delivery costs in the by-product method. The following schedules are presentations under both the by-product and co-product methods together with reconciliations to amounts reported in our consolidated financial statements.

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North America Copper Mines Product Revenues, Production Costs and Unit Net Cash Costs
Year Ended December 31, 2024  
(In millions)By-ProductCo-Product Method
MethodCopper
Molybdenuma
Otherb
Total
Revenues, excluding adjustments$5,417 

$5,417 $608 $186 $6,211 
Site production and delivery, before net noncash
    and other costs shown below		4,362 3,911 489 152 4,552 
By-product credits(604)— — — — 
Treatment charges 169 161 — 8 169 
Net cash costs 3,927 4,072 489 160 4,721 
DD&A439 394 36 9 439 
Noncash and other costs, net235 
c
222 11 2 235 
Total costs 4,601 4,688 536 171 5,395 
Gross profit $816 $729 $72 $15 $816 
     
Copper sales (millions of recoverable pounds)1,263 1,263 
Molybdenum sales (millions of recoverable pounds)a
30 
Gross profit per pound of copper/molybdenum:
Revenues, excluding adjustments$4.29 $4.29 $20.13 
Site production and delivery, before net noncash
    and other costs shown below		3.46 3.10 16.20 
By-product credits(0.48)— — 
Treatment charges0.13 0.12 — 
Unit net cash costs3.11 3.22 16.20 
DD&A0.34 0.31 1.19 
Noncash and other costs, net0.19 
c
0.18 0.36 
Total unit costs3.64 3.71 17.75 
Gross profit per pound$0.65 $0.58 $2.38 
Reconciliation to Amounts Reported
  
  Production
Revenuesand DeliveryDD&A
Totals presented above$6,211 $4,552 $439 
Treatment charges(4)165 — 
Noncash and other costs, net— 235 — 
Eliminations and other33 44 — 
North America copper mines6,240 4,996 439 
Other miningd
25,337 16,246 1,744 
Corporate, other & eliminations(6,122)(5,688)58 
As reported in our consolidated financial statements$25,455 $15,554 $2,241 
a.Reflects sales of molybdenum produced by certain of the North America copper mines to our molybdenum sales company at market-based pricing.
b.Includes gold and silver product revenues and production costs.
c.Includes charges totaling $62 million ($0.05 per pound of copper) for feasibility and optimization studies and $60 million ($0.05 per pound of copper) for metals inventory adjustments.
d.Represents the combined total for our other mining operations as presented in Note 14.



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North America Copper Mines Product Revenues, Production Costs and Unit Net Cash Costs
Year Ended December 31, 2023  
(In millions)By-ProductCo-Product Method
MethodCopper 
Molybdenuma
Otherb
Total
Revenues, excluding adjustments$5,368 $5,368 $710 $171 $6,249 
Site production and delivery, before net noncash
    and other costs shown below		4,093 3,621 535 149 4,305 
By-product credits(669)— — — — 
Treatment charges 169 161 — 8 169 
Net cash costs 3,593 3,782 535 157 4,474 
DD&A418 371 39 8 418 
Noncash and other costs, net242 
c
215 24 3 242 
Total costs 4,253 4,368 598 168 5,134 
Other revenue adjustments, primarily for pricing
    on prior period open sales		13 13 — — 13 
Gross profit$1,128 $1,013 $112 $3 $1,128 
Copper sales (millions of recoverable pounds)1,367 1,367 
Molybdenum sales (millions of recoverable pounds)a
30 
Gross profit per pound of copper/molybdenum:
Revenues, excluding adjustments$3.93 $3.93 $23.38 
Site production and delivery, before net noncash
    and other costs shown below		3.00 2.65 17.63 
By-product credits(0.49)— — 
Treatment charges0.12 0.12 — 
Unit net cash costs2.63 2.77 17.63 
DD&A0.30 0.27 1.30 
Noncash and other costs, net0.18 
c
0.16 0.77 
Total unit costs3.11 3.20 19.70 
Other revenue adjustments, primarily for pricing
    on prior period open sales		0.01 0.01 — 
Gross profit per pound$0.83 $0.74 $3.68 
Reconciliation to Amounts Reported      
   
  Production 
Revenuesand Delivery DD&A
Totals presented above$6,249 $4,305 $418 
Treatment charges(9)160 — 
Noncash and other costs, net— 242 — 
Other revenue adjustments, primarily for pricing
    on prior period open sales		13 —  — 
Eliminations and other63 71 — 
North America copper mines6,316 4,778  418 
Other miningd
22,791 14,867 1,586 
Corporate, other & eliminations(6,252)(6,018)64 
As reported in our consolidated financial statements$22,855 $13,627 $2,068 
a.Reflects sales of molybdenum produced by certain of the North America copper mines to our molybdenum sales company at market-based pricing.
b.Includes gold and silver product revenues and production costs.
c.Includes charges totaling $107 million ($0.08 per pound of copper) for feasibility and optimization studies and $11 million ($0.01 per pound of copper) for metals inventory adjustments.
d.Represents the combined total for our other mining operations as presented in Note 14.




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South America Operations Product Revenues, Production Costs and Unit Net Cash Costs
Year Ended December 31, 2024    
(In millions)By-ProductCo-Product Method
MethodCopper
Othera
Total
Revenues, excluding adjustments$4,894 $4,894 $446 $5,340 
Site production and delivery, before net noncash
    and other costs shown below		3,094 
b
2,865 281 3,146 
By-product credits(394)— — — 
Treatment charges193 193 — 193 
Royalty on metals8 7 1 8 
Net cash costs2,901 3,065 282 3,347 
DD&A446 409 37 446 
Noncash and other costs, net87 
c
85 2 87 
Total costs3,434 3,559 321 3,880 
Other revenue adjustments, primarily for pricing
    on prior period open sales		32 33 (1)32 
Gross profit $1,492 $1,368 $124 $1,492 
Copper sales (millions of recoverable pounds)1,177 1,177 
Gross profit per pound of copper:
Revenues, excluding adjustments$4.16 $4.16 
Site production and delivery, before net noncash
    and other costs shown below		2.63 
b
2.43 
By-product credits(0.34)— 
Treatment charges0.16 0.16 
Royalty on metals0.01 0.01 
Unit net cash costs2.46 2.60 
DD&A0.38 0.35 
Noncash and other costs, net0.08 
c
0.07 
Total unit costs2.92 3.02 
Other revenue adjustments, primarily for pricing
    on prior period open sales		0.03 0.03 
Gross profit per pound$1.27 $1.17 
Reconciliation to Amounts Reported   
  
  Production
Revenuesand DeliveryDD&A
Totals presented above$5,340 $3,146 $446 
Treatment charges(193)— — 
Royalty on metals(8)— — 
Noncash and other costs, net— 87 — 
Other revenue adjustments, primarily for pricing
    on prior period open sales		32 — — 
Eliminations and other— (3)— 
South America operations5,171 3,230 446 
Other miningd
26,406 18,012 1,737 
Corporate, other & eliminations(6,122)(5,688)58 
As reported in our consolidated financial statements$25,455 $15,554 $2,241 
a.Includes silver sales of 3.6 million ounces ($29.35 per ounce average realized price) and sales of molybdenum produced by Cerro Verde to our molybdenum sales company at market-based pricing.
b.Includes $97 million ($0.08 per pound of copper) associated with nonrecurring labor-related charges at Cerro Verde related to the new CLAs with its unions.
c.Includes charges totaling $57 million ($0.05 per pound of copper) for feasibility and optimization studies.
d.Represents the combined total for our other mining operations as presented in Note 14.


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South America Operations Product Revenues, Production Costs and Unit Net Cash Costs
Year Ended December 31, 2023     
(In millions)By-ProductCo-Product Method
MethodCopper 
Othera
Total
Revenues, excluding adjustments$4,583 $4,583 $526 $5,109 
Site production and delivery, before net noncash
    and other costs shown below		3,083 2,810 339 3,149 
By-product credits(463)— — — 
Treatment charges234 234 — 234 
Royalty on metals8 7 1 8 
Net cash costs2,862 3,051 340 3,391 
DD&A459 412 47 459 
Noncash and other costs, net92 
b
87 5 92 
Total costs3,413 3,550 392 3,942 
Other revenue adjustments, primarily for pricing
    on prior period open sales		71 71 3 74 
Gross profit$1,241 $1,104 $137 $1,241 
Copper sales (millions of recoverable pounds)1,200 1,200 
Gross profit per pound of copper:
Revenues, excluding adjustments$3.82 $3.82 
Site production and delivery, before net noncash
    and other costs shown below		2.57 2.34 
By-product credits(0.39)— 
Treatment charges0.19 0.19 
Royalty on metals0.01 0.01 
Unit net cash costs2.38 2.54 
DD&A0.38 0.35 
Noncash and other costs, net0.08 
b
0.07 
Total unit costs2.84 2.96 
Other revenue adjustments, primarily for pricing
    on prior period open sales		0.06 0.06 
Gross profit per pound$1.04 $0.92 
Reconciliation to Amounts Reported    
   
  Production 
Revenuesand Delivery DD&A
Totals presented above$5,109 $3,149 $459 
Treatment charges(234)— — 
Royalty on metals(8)— — 
Noncash and other costs, net— 92  — 
Other revenue adjustments, primarily for pricing
    on prior period open sales		74 —  — 
Eliminations and other— (2)— 
South America operations4,941 3,239  459 
Other miningc
24,166 16,406 1,545 
Corporate, other & eliminations(6,252)(6,018)64 
As reported in our consolidated financial statements$22,855 $13,627 $2,068 
a.Includes silver sales of 4.1 million ounces ($23.57 per ounce average realized price) and sales of molybdenum produced by Cerro Verde to our molybdenum sales company at market-based pricing.
b.Includes charges totaling $44 million ($0.04 per pound of copper) for feasibility and optimization studies.
c.Represents the combined total for our other mining operations as presented in Note 14.


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Indonesia Operations Product Revenues, Production Costs and Unit Net Cash (Credits) Costs
Year Ended December 31, 2024  
(In millions)Co-Product Method
By-Product
Method		CopperGold
Silver & Othera
Total
Revenues, excluding adjustments$6,842 $6,842 $4,389 $218 $11,449 
Site production and delivery, before net noncash
    and other costs shown below		2,681 1,602 1,028 51 2,681 
Gold, silver and other by-product credits(4,605)— — — — 
Treatment charges571 341 219 11 571 
Export duties457 273 175 9 457 
Royalty on metals433 260 167 6 433 
Net cash (credits) costs(463)2,476 1,589 77 4,142 
DD&A1,193 713 457 23 1,193 
Noncash and other costs, net362 
b
217 139 6 362 
Total costs1,092 3,406 2,185 106 5,697 
Other revenue adjustments, primarily for pricing
    on prior period open sales		7 7 (1)(1)5 
Gross profit $5,757 $3,443 $2,203 $111 $5,757 
Copper sales (millions of recoverable pounds)1,632 1,632 
Gold sales (thousands of recoverable ounces)1,817 
Gross profit per pound of copper/per ounce of gold:
Revenues, excluding adjustments$4.19 $4.19 $2,418 
Site production and delivery, before net noncash
    and other costs shown below		1.64 0.98 566 
Gold, silver and other by-product credits(2.82)— — 
Treatment charges0.35 0.21 120 
Export duties0.28 0.17 96 
Royalty on metals0.27 0.16 92 
Unit net cash (credits) costs(0.28)1.52 874 
DD&A0.73 0.44 252 
Noncash and other costs, net0.22 
b
0.13 77 
Total unit costs0.67 2.09 1,203 
Other revenue adjustments, primarily for pricing
    on prior period open sales		0.01 0.01 (2)
Gross profit per pound/ounce$3.53 $2.11 $1,213 
Reconciliation to Amounts Reported    
   
  Production 
Revenuesand DeliveryDD&A 
Totals presented above$11,449 $2,681 $1,193  
Treatment charges(245)326 
c
—  
Export duties(457)— — 
Royalty on metals(433)— —  
Noncash and other costs, net— 362 —  
Other revenue adjustments, primarily for pricing
    on prior period open sales		5 — —  
Eliminations and other(1)(1)— 
Indonesia operations10,318 3,368 1,193  
Other miningd
21,259 17,874 990  
Corporate, other & eliminations(6,122)(5,688)58  
As reported in our consolidated financial statements$25,455 $15,554 $2,241  
a.Includes silver sales of 6.9 million ounces ($28.52 per ounce average realized price).
b.Includes charges totaling (i) $144 million ($0.09 per pound of copper) associated with ARO adjustments, (ii) $133 million ($0.08 per pound of copper) for operational readiness and startup costs associated with the new downstream processing facilities, (iii) $34 million ($0.02 per pound of copper) related to amounts capitalized in prior years associated with the construction of the new downstream processing facilities, and (iv) $28 million ($0.02 per pound of copper) for feasibility and optimization studies.
c.Represents tolling costs paid to PT Smelting.
d.Represents the combined total for our other mining operations as presented in Note 14.
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Indonesia Operations Product Revenues, Production Costs and Unit Net Cash Costs
Year Ended December 31, 2023  
(In millions)Co-Product Method
By-Product
Method		Copper Gold
Silver & Othera
Total
Revenues, excluding adjustments$5,801 $5,801 $3,346 $157 $9,304 
Site production and delivery, before net noncash
    and other costs shown below		2,467 1,538 887 42 2,467 
Gold, silver and other by-product credits(3,520)— — — — 
Treatment charges537 335 193 9 537 
Export duties324 202 117 5 324 
Royalty on metals338 212 121 5 338 
Net cash costs146 2,287 1,318 61 3,666 
DD&A1,028 641 370 17 1,028 
Noncash and other costs, net22 
b
14 8 — 22 
Total costs1,196 2,942 1,696 78 4,716 
Other revenue adjustments, primarily for pricing
    on prior period open sales		114 114 18 (1)131 
PT Smelting intercompany profit112 70 40 2 112 
Gross profit $4,831 $3,043 $1,708 $80 $4,831 
Copper sales (millions of recoverable pounds)1,525 1,525 
Gold sales (thousands of recoverable ounces)1,697 
Gross profit per pound of copper/per ounce of gold:
Revenues, excluding adjustments$3.81 $3.81 $1,972 
Site production and delivery, before net noncash
    and other costs shown below		1.62 1.01 522 
Gold, silver and other by-product credits(2.30)— — 
Treatment charges0.35 0.22 114 
Export duties0.21 0.13 69 
Royalty on metals0.22 0.14 71 
Unit net cash costs0.10 1.50 776 
DD&A0.68 0.42 218 
Noncash and other costs, net0.01 
b
0.01 5 
Total unit costs0.79 1.93 999 
Other revenue adjustments, primarily for pricing
    on prior period open sales		0.08 0.07 9 
PT Smelting intercompany profit0.07 0.05 24 
Gross profit per pound/ounce$3.17 $2.00 $1,006 
Reconciliation to Amounts Reported     
  Production  
Revenuesand Delivery DD&A 
Totals presented above$9,304 $2,467 $1,028  
Treatment charges(336)201 
c
—  
Export duties(324)— — 
Royalty on metals(338)— —  
Noncash and other costs, net— 22 —  
Other revenue adjustments, primarily for pricing
    on prior period open sales		131 — —  
PT Smelting intercompany profit— (112)— 
Eliminations and other— (8)— 
Indonesia operations8,437 2,570  1,028  
Other miningd
20,670 17,075 976  
Corporate, other & eliminations(6,252)(6,018)64  
As reported in our consolidated financial statements$22,855 $13,627 $2,068  
a.Includes silver sales of 6.0 million ounces ($23.37 per ounce average realized price).
b.Includes credits of $112 million ($0.07 per pound of copper) associated with ARO adjustments, and charges of $55 million ($0.04 per pound of copper) associated with an administrative fine and $27 million ($0.02 per pound of copper) for feasibility and optimization studies.
c.Represents tolling costs paid to PT Smelting.
d.Represents the combined total for our other mining operations as presented in Note 14.
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Molybdenum Mines Product Revenues, Production Costs and Unit Net Cash Costs
 Years Ended December 31,
(In millions)20242023
Revenues, excluding adjustmentsa
$619 $702  
Site production and delivery, before net noncash
    and other costs shown below		508 423  
Treatment charges and other27 25  
Net cash costs535 448  
DD&A73 66  
Noncash and other costs, net22 16 
Total costs630 530  
Gross (loss) profit $(11)$172  
Molybdenum sales (millions of recoverable pounds)a
30 30 
Gross (loss) profit per pound of molybdenum:
Revenues, excluding adjustmentsa
$20.66 $23.71 
Site production and delivery, before net noncash
    and other costs shown below		16.99 14.28 
Treatment charges and other0.90 0.85 
Unit net cash costs17.89 15.13 
DD&A2.43 2.24 
Noncash and other costs, net0.73 0.55 
Total unit costs21.05 17.92 
Gross (loss) profit per pound$(0.39)$5.79 
Reconciliation to Amounts Reported
   
 Production  
Year Ended December 31, 2024Revenuesand Delivery DD&A 
Totals presented above$619 $508 $73 
Treatment charges and other(27)— — 
Noncash and other costs, net— 22 — 
Molybdenum mines592 530 73 
Other miningb
30,985 20,712 2,110 
Corporate, other & eliminations(6,122)(5,688)58 
As reported in our consolidated financial statements$25,455 $15,554 $2,241 
Year Ended December 31, 2023     
Totals presented above$702 $423 $66 
Treatment charges and other(25)— — 
Noncash and other costs, net— 16 —  
Molybdenum mines677 439  66  
Other miningb
28,430 19,206 1,938 
Corporate, other & eliminations(6,252)(6,018)64 
As reported in our consolidated financial statements$22,855 $13,627 $2,068 
a.Reflects sales of the Molybdenum mines’ production to the molybdenum sales company at market-based pricing. On a consolidated basis, realizations are based on the actual contract terms for sales to third parties; as a result, our consolidated average realized price per pound of molybdenum will differ from the amounts reported in this table.
b.Represents the combined total for our other mining operations as presented in Note 14. Also includes amounts associated with the molybdenum sales company, which includes sales of molybdenum produced by the Molybdenum mines and by certain of the North America and South America copper mines.

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CAUTIONARY STATEMENT

Our discussion and analysis contains forward-looking statements in which we discuss our potential future performance, operations and projects. Forward-looking statements are all statements other than statements of historical facts, such as plans, projections, or expectations relating to business outlook, strategy, goals or targets; global market conditions; ore grades and milling rates; production and sales volumes; unit net cash costs (credits) and operating costs; capital expenditures; operating plans (including mine sequencing); cash flows; liquidity; PT-FI’s commissioning, remediation and full ramp-up of its new smelter and full production at the PMR; potential extension of PT-FI’s IUPK beyond 2041; export licenses, export duties, and export volumes, including PT-FI’s ability to continue exports of copper concentrate until full ramp-up is achieved at its new smelter in Indonesia; timing of shipments of inventoried production; our commitment to deliver responsibly produced copper and molybdenum, including plans to implement, validate and maintain validation of our operating sites under specific frameworks; execution of our energy and climate strategies and the underlying assumptions and estimated impacts on our business and stakeholders related thereto; achievement of 2030 climate targets and 2050 net zero aspiration; improvements in operating procedures and technology innovations and applications; exploration efforts and results; development and production activities, rates and costs; future organic growth opportunities; tax rates; the impact of copper, gold and molybdenum price changes; the impact of deferred intercompany profits on earnings; mineral reserve and mineral resource estimates; final resolution of settlements associated with ongoing legal and environmental proceedings; debt repurchases; and the ongoing implementation of our financial policy and future returns to shareholders, including dividend payments (base or variable) and share repurchases. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “targets,” “intends,” “likely,” “will,” “should,” “could,” “to be,” ”potential,” “assumptions,” “guidance,” “aspirations,” “future,” “commitments,” “pursues,” “initiatives,” “objectives,” “opportunities,” “strategy” and any similar expressions are intended to identify those assertions as forward-looking statements. The declaration and payment of dividends (base or variable), and timing and amount of any share repurchases are at the discretion of our Board and management, respectively, and are subject to a number of factors, including not exceeding our net debt target, capital availability, our financial results, cash requirements, global economic conditions, changes in laws, contractual restrictions and other factors deemed relevant by our Board or management, as applicable. Our share repurchase program may be modified, increased, suspended or terminated at any time at the Board’s discretion.

We caution readers that forward-looking statements are not guarantees of future performance and actual results may differ materially from those anticipated, expected, projected or assumed in the forward-looking statements. Important factors that can cause our actual results to differ materially from those anticipated in the forward-looking statements include, but are not limited to, supply of and demand for, and prices of the commodities we produce, primarily copper and gold; PT-FI’s ability to export and sell or inventory copper concentrates through remediation and full ramp-up of its new smelter in Indonesia; changes in export duties; completion of remediation activities and achieving full ramp-up of the new smelter in Indonesia; full production at the PMR; production rates; timing of shipments; price and availability of consumables and components we purchase as well as constraints on supply and logistics, and transportation services; changes in our cash requirements, financial position, financing or investment plans; changes in general market, economic, geopolitical, regulatory or industry conditions; reductions in liquidity and access to capital; changes in tax laws and regulations; political and social risks, including the potential effects of violence in Indonesia, civil unrest in Peru, and relations with local communities and Indigenous Peoples; operational risks inherent in mining, with higher inherent risks in underground mining; mine sequencing; changes in mine plans or operational modifications, delays, deferrals or cancellations, including the ability to smelt and refine or inventory; results of technical, economic or feasibility studies; potential inventory adjustments; potential impairment of long-lived mining assets; satisfaction of requirements in accordance with PT-FI’s IUPK to extend mining rights from 2031 through 2041; process relating to the extension of PT-FI’s IUPK beyond 2041; cybersecurity risks; any major public health crisis; labor relations, including labor-related work stoppages and increased costs; compliance with applicable environmental, health and safety laws and regulations; weather- and climate-related risks; environmental risks, including availability of secure water supplies; impacts, expenses or results from litigation or investigations; tailings management; our ability to comply with our responsible production commitments under specific frameworks; and any changes to such frameworks and other factors described in more detail in Item 1A. “Risk Factors” contained in Part I of our annual report on Form 10-K for the year ended December 31, 2024.

Investors are cautioned that many of the assumptions upon which our forward-looking statements are based are likely to change after the date the forward-looking statements are made, including for example commodity prices, which we cannot control, and production volumes and costs or technological solutions and innovations, some aspects of which we may not be able to control. Further, we may make changes to our business plans that could affect our results. We undertake no obligation to update any forward-looking statements, which speak only as of the date made, notwithstanding any changes in our assumptions, changes in business plans, actual experience or other changes.

Estimates of mineral reserves and mineral resources are subject to considerable uncertainty. Such estimates are, to a large extent, based on metal prices for the commodities we produce and interpretations of geologic data, which may not necessarily be indicative of future results or quantities ultimately recovered. Our annual report on Form 10-K for the year ended December 31, 2024, also includes forward-looking statements regarding mineral resources not included in proven and probable mineral reserves. A mineral resource, which includes measured, indicated and inferred mineral resources, is a concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. Such a deposit cannot qualify as recoverable proven and probable mineral reserves until legal and economic feasibility are confirmed based upon a comprehensive evaluation of development and
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operating costs, grades, recoveries and other material modifying factors. Accordingly, no assurance can be given that the estimated mineral resources will become proven and probable mineral reserves.

Our annual report on Form 10-K for the year ended December 31, 2024, also contains measures such as net debt and unit net cash costs (credits) per pound of copper and molybdenum, which are not recognized under U.S. GAAP. Refer to “Operations – Unit Net Cash Costs (Credits)” for further discussion of unit net cash costs (credits) associated with our operating divisions, and to “Product Revenues and Production Costs” for reconciliations of per pound costs by operating division to production and delivery costs applicable to sales reported in our consolidated financial statements. Refer to “Net Debt” for reconciliations of consolidated debt, consolidated cash and cash equivalents and current restricted cash associated with PT-FI’s export proceeds to net debt. For forward-looking unit net cash costs (credits) per pound of copper and molybdenum measures, we are unable to provide a reconciliation to the most comparable GAAP measure without unreasonable effort because estimating such GAAP measures and providing a meaningful reconciliation is extremely difficult and requires a level of precision that is unavailable for these future periods and the information needed to reconcile these measures is dependent upon future events, many of which are outside of our control as described above. Forward-looking non-GAAP measures are estimated consistent with the relevant definitions and assumptions.
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Item 8. Financial Statements and Supplementary Data.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Freeport-McMoRan Inc.’s (the Company’s) management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

•Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets;

•Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, including our principal executive officer and principal financial officer, assessed the effectiveness of our internal control over financial reporting as of the end of the fiscal year covered by this annual report on Form 10-K. In making this assessment, our management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Based on its assessment, management concluded that, as of December 31, 2024, our Company’s internal control over financial reporting is effective based on the COSO criteria.

Ernst & Young LLP, an independent registered public accounting firm, who audited the Company’s consolidated financial statements included in this Form 10-K, has issued an attestation report on the Company’s internal control over financial reporting, which is included herein.

/s/ Kathleen L. Quirk /s/ Maree E. Robertson
Kathleen L. Quirk Maree E. Robertson
President and Executive Vice President and
Chief Executive Officer Chief Financial Officer
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Freeport-McMoRan Inc.
Opinion on Internal Control Over Financial Reporting

We have audited Freeport-McMoRan Inc.’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Freeport-McMoRan Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
    
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 14, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP
Phoenix, Arizona
February 14, 2025
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Freeport-McMoRan Inc.

Opinion on the Financial Statements
 
We have audited the accompanying consolidated balance sheets of Freeport-McMoRan Inc. (the Company) as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 14, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Tax Contingencies
Description of the MatterAs discussed in Note 10 to the consolidated financial statements, the Company operates in multiple tax jurisdictions, and its income tax returns are subject to examination by tax authorities in those jurisdictions who may challenge any tax position on these returns. Uncertainty in a tax position may arise because tax laws are subject to interpretation. The Company uses significant judgment, specifically as it relates to Peru and Indonesia, to determine whether, based on the technical merits, a tax position is more likely than not to be sustained upon examination by taxing authorities.
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Auditing management’s tax positions involved significant auditor judgment, because management’s tax positions require a high degree of judgment and are based on interpretations of tax laws and legal rulings.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s accounting process for tax contingencies. This included testing controls over management’s review of the technical merits of tax positions and disputed tax assessments, including the process to measure the financial statement impact of these tax matters.
Our audit procedures included, among others, evaluating the Company’s accounting for these tax positions by using our knowledge of and experience with the application of respective tax laws by the relevant tax authorities, and/or our understanding of the contractual arrangements with the applicable government, if the position is governed by a contract. We analyzed the Company’s assumptions and data used to determine the tax assessments and tested the accuracy of the calculations. We involved our tax professionals located in the respective jurisdictions to assess the technical merits of the Company’s tax positions and to evaluate the application of relevant tax laws in the Company’s recognition determination. We obtained and assessed the Company’s correspondence with the relevant tax authorities and, as applicable, third-party tax or legal opinions or other external correspondence and analyses. We also evaluated the adequacy of the Company’s disclosures included in Notes 9 and 10 in relation to these tax matters.
Environmental Obligations
Description of the Matter
As discussed in Note 10 to the consolidated financial statements, the Company is subject to various national, state and local environmental laws and regulations that govern the protection of the environment, including remediation, restoration and reclamation of environmental contamination. Liabilities for environmental contingencies are recorded when it is probable that obligations have been incurred and the costs can be reasonably estimated. As of December 31, 2024, the Company’s consolidated environmental obligations totaled $2.0 billion.
Auditing management’s accounting for environmental obligations was challenging because significant judgment is required by the Company to estimate the future costs to remediate the environmental matters. The significant judgment was primarily due to the inherent estimation uncertainty relating to the amount of future costs. Such uncertainties involve assumptions regarding the nature and extent of site contamination, the anticipated costs, scope and timing of remediation activities and required remediation methods under presently enacted laws and regulations, and allocation of costs among other potentially responsible parties.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s measurement of the environmental obligations. For example, we tested controls over management’s review of the environmental obligations calculations and management’s assessment to evaluate key judgments and estimates affecting the environmental obligations.
To test the Company’s measurement of the environmental obligations, among other procedures, we inspected correspondence with regulatory agencies, including correspondence related to remediation activities and methods and potentially responsible parties, obtained external legal counsel confirmation letters, and inspected environmental studies. Additionally, we tested the accuracy and completeness of the underlying data used in the Company’s analyses and tested the significant assumptions discussed above. We utilized our environmental professionals to search for new or contrary evidence related to the Company’s sites and to assist in evaluating the estimated future costs by comparing the estimated future costs to environmental permits, third party observable data such as vendor quotes, and to historical costs incurred for similar activities.
/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.
Phoenix, Arizona
February 14, 2025
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Freeport-McMoRan Inc.
CONSOLIDATED STATEMENTS OF INCOME
 Years Ended December 31,
 202420232022
 (In millions, except per share amounts)
Revenues$25,455 $22,855 $22,780 
Cost of sales:   
Production and delivery15,554 13,627 13,070 
Depreciation, depletion and amortization2,241 2,068 2,019 
Total cost of sales17,795 15,695 15,089 
Selling, general and administrative expenses513 479 420 
Exploration and research expenses156 137 115 
Environmental obligations and shutdown costs127 319 121 
Net gain on sales of assets— — (2)
Total costs and expenses18,591 16,630 15,743 
Operating income 6,864 6,225 7,037 
Interest expense, net(319)(515)(560)
Net gain on early extinguishment of debt— 10 31 
Other income, net362 286 207 
Income before income taxes and equity in affiliated companies’ net earnings6,907 6,006 6,715 
Provision for income taxes(2,523)(2,270)(2,267)
Equity in affiliated companies’ net earnings15 15 31 
Net income4,399 3,751 4,479 
Net income attributable to noncontrolling interests(2,510)(1,903)(1,011)
Net income attributable to common stockholders$1,889 $1,848 $3,468 
Net income per share attributable to common stockholders:   
Basic$1.31 $1.28 $2.40 
Diluted$1.30 $1.28 $2.39 
Weighted-average common shares outstanding:   
Basic1,438 1,434 1,441 
Diluted1,445 1,443 1,451 
Dividends declared per share of common stock$0.60 $0.60 $0.60 
The accompanying Notes to Consolidated Financial Statements are an integral part of these consolidated financial statements.

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Freeport-McMoRan Inc.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years Ended December 31,
202420232022
(In millions)
Net income$4,399 $3,751 $4,479 
Other comprehensive (loss) income, net of taxes:
Defined benefit plans:
Actuarial (losses) gains arising during the period, net of taxes(44)39 62 
Prior service costs arising during the period— — (1)
Amortization of unrecognized amounts included in net periodic benefit costs3 5 8 
Foreign exchange losses(1)— (1)
Other comprehensive (loss) income(42)44 68 
Total comprehensive income4,357 3,795 4,547 
Total comprehensive income attributable to noncontrolling interests
(2,508)(1,901)(1,011)
Total comprehensive income attributable to common stockholders$1,849 $1,894 $3,536 
The accompanying Notes to Consolidated Financial Statements are an integral part of these consolidated financial statements.


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Freeport-McMoRan Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 Years Ended December 31,
202420232022
 (In millions)
Cash flow from operating activities:   
Net income$4,399 $3,751 $4,479 
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, depletion and amortization2,241 2,068 2,019 
Net charges for environmental and asset retirement obligations, including accretion622 295 369 
Payments for environmental and asset retirement obligations(234)(250)(274)
Stock-based compensation109 109 95 
Talc-related litigation charges— 65 — 
Net charges for defined pension and postretirement plans35 62 45 
Pension plan contributions(78)(75)(54)
Net gain on early extinguishment of debt— (10)(31)
Deferred income taxes(76)182 36 
Changes in deferred profit on PT Freeport Indonesia’s sales to PT Smelting— (112)(14)
Charges for social investment programs at PT Freeport Indonesia103 84 84 
Payments for social investment programs at PT Freeport Indonesia(54)(44)(11)
Impairment of oil and gas properties69 67 — 
Other, net53 (33)(3)
Changes in working capital and other:   
Accounts receivable460 166 56 
Inventories(638)(873)(573)
Other current assets(41)(29)(12)
Accounts payable and accrued liabilities143 (161)(73)
Accrued income taxes and timing of other tax payments47 17 (999)
Net cash provided by operating activities7,160 5,279 5,139 
Cash flow from investing activities:   
Capital expenditures:   
North America copper mines(1,033)(761)(597)
South America operations(375)(368)(304)
Indonesia operations(2,908)(3,411)(2,381)
Molybdenum mines(117)(84)(33)
Other(375)(200)(154)
Proceeds from sales of assets19 27 108 
Acquisition of additional ownership interest in Cerro Verde(210)— — 
Loans to PT Smelting for expansion(28)(129)(65)
Other, net(1)(30)(14)
Net cash used in investing activities(5,028)(4,956)(3,440)
Cash flow from financing activities:   
Proceeds from debt2,251 1,781 5,735 
Repayments of debt(2,731)(2,980)(4,515)
Finance lease payments(41)(3)(7)
Cash dividends and distributions paid:   
Common stock(865)(863)(866)
Noncontrolling interests(1,833)(625)(840)
Treasury stock purchases(59)— (1,347)
Contributions from noncontrolling interests— 50 189 
Proceeds from exercised stock options29 47 125 
Payments for withholding of employee taxes related to stock-based awards(35)(50)(55)
Debt financing costs — (7)(42)
Net cash used in financing activities(3,284)(2,650)(1,623)
Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents (1,152)(2,327)76 
Cash, cash equivalents and restricted cash and cash equivalents at beginning of year6,063 8,390 8,314 
Cash, cash equivalents and restricted cash and cash equivalents at end of year$4,911 $6,063 $8,390 
The accompanying Notes to Consolidated Financial Statements are an integral part of these consolidated financial statements.
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Freeport-McMoRan Inc.
CONSOLIDATED BALANCE SHEETS
 December 31,
 20242023
 (In millions, except par value)
ASSETS  
Current assets:  
Cash and cash equivalents$3,923 $4,758 
Restricted cash and cash equivalents888 1,208 
Trade accounts receivable578 1,209 
Value added and other tax receivables564 455 
Inventories:  
Product3,038 2,472 
Materials and supplies, net2,382 2,169 
Mill and leach stockpiles1,388 1,419 
Other current assets535 375 
Total current assets13,296 14,065 
Property, plant, equipment and mine development costs, net 38,514 35,295 
Long-term mill and leach stockpiles1,225 1,336 
Other assets1,813 1,810 
Total assets$54,848 $52,506 
LIABILITIES AND EQUITY  
Current liabilities:  
Accounts payable and accrued liabilities$4,057 $3,729 
Accrued income taxes859 786 
Current portion of environmental and asset retirement obligations320 316 
Dividends payable219 218 
Current portion of debt41 766 
Total current liabilities5,496 5,815 
Long-term debt, less current portion8,907 8,656 
Environmental and asset retirement obligations, less current portion5,404 4,624 
Deferred income taxes4,376 4,453 
Other liabilities1,887 1,648 
Total liabilities26,070 25,196 
Equity:  
Stockholders’ equity:  
Common stock, par value $0.10, 1,624 shares and 1,619 shares issued, respectively
162 162 
Capital in excess of par value23,797 24,637 
Accumulated deficit(170)(2,059)
Accumulated other comprehensive loss(314)(274)
Common stock held in treasury – 187 shares and 184 shares, respectively, at cost
(5,894)(5,773)
Total stockholders’ equity17,581 16,693 
Noncontrolling interests11,197 10,617 
Total equity28,778 27,310 
Total liabilities and equity$54,848 $52,506 
The accompanying Notes to Consolidated Financial Statements are an integral part of these consolidated financial statements.

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Freeport-McMoRan Inc.
CONSOLIDATED STATEMENTS OF EQUITY
 Stockholders’ Equity
Common Stock Accumulated DeficitAccumu-
lated
Other Compre-hensive
Loss		Common Stock
Held in Treasury		Total
Stock-
holders’
Equity
Number
of
Shares		At Par
Value		Capital in
Excess of
Par Value		Number
of
Shares		At
Cost		Non-
controlling
Interests		Total
Equity
 (In millions)
Balance at January 1, 20221,603 $160 $25,875 $(7,375)$(388)146 $(4,292)$13,980 $9,039 $23,019 
Exercised and issued stock-based awards10 1 131 — — — — 132 — 132 
Stock-based compensation, including the tender of shares— — 88 — — 2 (62)26 (11)15 
Treasury stock purchases— — — — — 35 (1,347)(1,347)— (1,347)
Dividends— — (864)— — — — (864)(820)(1,684)
Contributions from noncontrolling interests— — 92 — — — — 92 97 189 
Net income attributable to common stockholders— — — 3,468 — — — 3,468 — 3,468 
Net income attributable to noncontrolling interests— — — — — — — — 1,011 1,011 
Other comprehensive income— — — — 68 — — 68 — 68 
Balance at December 31, 20221,613 161 25,322 (3,907)(320)183 (5,701)15,555 9,316 24,871 
Exercised and issued stock-based awards6 1 68 — — — — 69 — 69 
Stock-based compensation, including the tender of shares
— — 87 — — 1 (72)15 (1)14 
Dividends— — (864)— — — — (864)(625)(1,489)
Contributions from noncontrolling interests— — 24 — — — — 24 26 50 
Net income attributable to common stockholders— — — 1,848 — — — 1,848 — 1,848 
Net income attributable to noncontrolling interests
— — — — — — — — 1,903 1,903 
Other comprehensive income (loss)— — — — 46 — — 46 (2)44 
Balance at December 31, 20231,619 162 24,637 (2,059)(274)184 (5,773)16,693 10,617 27,310 
Exercised and issued stock-based awards5 — 56 — — 1 — 56 — 56 
Stock-based compensation, including the tender of shares
— — 92 — — 1 (62)30 (4)26 
Treasury stock purchases— — — — — 1 (59)(59)— (59)
Acquisition of additional ownership interest in Cerro Verde— — (125)— — — — (125)(90)(215)
Dividends— — (866)— — — — (866)(1,833)(2,699)
Change in consolidated subsidiary ownership interests— — 3 — — — — 3 (1)2 
Net income attributable to common stockholders— — — 1,889 — — — 1,889 — 1,889 
Net income attributable to noncontrolling interests
— — — — — — — — 2,510 2,510 
Other comprehensive loss— — — — (40)— — (40)(2)(42)
Balance at December 31, 20241,624 $162 $23,797 $(170)$(314)187 $(5,894)$17,581 $11,197 $28,778 
The accompanying Notes to Consolidated Financial Statements are an integral part of these consolidated financial statements.


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Freeport-McMoRan Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation.  The consolidated financial statements of Freeport-McMoRan Inc. (FCX) include the accounts of those subsidiaries where it directly or indirectly has more than 50% of the voting rights and/or has control over the subsidiary. As of December 31, 2024, the most significant entities that FCX consolidates include its 48.76%-owned subsidiary PT Freeport Indonesia (PT-FI) and its wholly owned subsidiary, Freeport Minerals Corporation (FMC). Refer to Note 2 for further discussion, including FCX’s conclusion to consolidate PT-FI.

FMC’s unincorporated joint venture at Morenci is reflected using the proportionate consolidation method (refer to Note 2). Investments in unconsolidated companies over which FCX has the ability to exercise significant influence, but does not control, are accounted for under the equity method and include PT-FI’s investment in PT Smelting (refer to Note 2). Investments in unconsolidated companies owned less than 20%, and for which FCX does not exercise significant influence, are recorded at (i) fair value for those that have a readily determinable fair value or (ii) cost, less any impairment, for those that do not have a readily determinable fair value. All significant intercompany transactions have been eliminated. Dollar amounts in tables are stated in millions, except per share amounts.

Business Segments.  FCX has organized its mining operations into four primary divisions – North America copper mines, South America operations, Indonesia operations and Molybdenum mines, and operating segments that meet certain thresholds are reportable segments. FCX’s reportable segments include the Morenci and Cerro Verde copper mines, the integrated Indonesia operations (including the Grasberg minerals district and PT-FI’s new smelter and precious metals refinery (PMR) - collectively - PT-FI’s new downstream processing facilities), the Rod & Refining operations and Atlantic Copper Smelting & Refining (Atlantic Copper, S.L.U. (Atlantic Copper)). Refer to Note 14 for further discussion.

Use of Estimates.  The preparation of FCX’s financial statements in conformity with accounting principles generally accepted in the United States (U.S.) requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. The more significant areas requiring the use of management estimates include mineral reserve estimation; asset lives for depreciation, depletion and amortization; environmental obligations; asset retirement obligations (AROs); estimates of recoverable copper in mill and leach stockpiles; deferred taxes and valuation allowances; reserves for contingencies and litigation; asset impairment, including estimates used to derive future cash flows associated with those assets; pension benefits; and valuation of derivative instruments. Actual results could differ from those estimates.

Functional Currency. The functional currency for the majority of FCX’s foreign operations is the U.S. dollar. For foreign subsidiaries whose functional currency is the U.S. dollar, monetary assets and liabilities denominated in the local currency are translated at current exchange rates, and non-monetary assets and liabilities, such as inventories, property, plant, equipment and mine development costs, are translated at historical exchange rates. Gains and losses resulting from translation of such account balances are included in other income, net, as are gains and losses from foreign currency transactions. Foreign currency net gains totaled $17 million in 2024, $20 million in 2023 and $9 million in 2022.

Cash and Cash Equivalents.  Highly liquid investments purchased with maturities of three months or less are considered cash equivalents.

Restricted Cash and Cash Equivalents. Restricted cash and cash equivalents are classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. FCX’s restricted cash and cash equivalents are primarily related to a portion of PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks for 90 days in accordance with Indonesia regulations, assurance bonds to support PT-FI’s commitment for smelter development in Indonesia, and guarantees and commitments for certain mine closure obligations. Refer to Notes 10 and 12 for further information.
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Inventories.  Inventories include product, materials and supplies, and mill and leach stockpiles. Inventories are stated at the lower of weighted-average cost or net realizable value (NRV).

Product. Product inventories represent copper, gold, and molybdenum products in various salable forms that are valued based on the weighted-average cost of source material plus applicable conversion costs at our processing facilities. Product inventories include labor and benefits, supplies, energy, depreciation, depletion, amortization, site overhead costs and other necessary costs associated with the extraction and processing of ore, such as mining, milling, smelting, leaching, solution extraction and electrowinning (SX/EW), refining, roasting and chemical processing. Product inventories exclude corporate general and administrative costs.

Materials and Supplies, net. Materials and supplies inventory of $2.4 billion at December 31, 2024, and $2.2 billion at December 31, 2023, is net of obsolescence reserves totaling $54 million at December 31, 2024, and $41 million at December 31, 2023.

Mill and Leach Stockpiles. Mill and leach stockpiles are work-in-process inventories for FCX’s mining operations. Estimated metals in stockpiles not expected to be recovered within the next 12 months are classified as long-term. Mill and leach stockpiles contain ore that has been extracted from an ore body and is available for metal recovery. Mill stockpiles contain sulfide ores, and recovery of metal is through milling, concentrating and smelting and refining or, alternatively, by concentrate leaching. Leach stockpiles contain oxide ores and certain secondary sulfide ores and recovery of metal is through exposure to acidic solutions that dissolve contained copper and deliver it in solution to extraction processing facilities (i.e., SX/EW). The recorded cost of mill and leach stockpiles includes mining and haulage costs incurred to deliver ore to stockpiles, depreciation, depletion, amortization and site overhead costs. Material is removed from the stockpiles at a weighted-average cost per pound. Each mine site maintains one work-in-process balance on a weighted-average cost basis for each process (i.e., leach, mill or concentrate leach) regardless of the number of stockpile systems at that site.

Because it is impracticable to determine copper contained in mill and leach stockpiles by physical count, reasonable estimation methods are employed. The quantity of material delivered to mill and leach stockpiles is based on surveyed volumes of mined material and daily production records. Sampling and assaying of blasthole cuttings determine the estimated copper grade of the material delivered to mill and leach stockpiles.

Expected copper recoveries for mill stockpiles are determined by metallurgical testing. The recoverable copper in mill stockpiles, once entered into the production process, can be produced into copper concentrate almost immediately.

Expected copper recoveries for leach stockpiles are determined using small-scale laboratory tests, small- to large-scale column testing (which simulates the production process), historical trends and other factors, including mineralogy of the ore and rock type. Total copper recovery in leach stockpiles can vary significantly from a low percentage to more than 80% depending on several variables, including processing methodology, processing variables, mineralogy and particle size of the rock. For newly placed material on active stockpiles, as much as 80% of the total copper recovery may occur during the first year, and the remaining copper may be recovered over many years.

Process rates and copper recoveries for mill and leach stockpiles are monitored regularly, and recovery estimates are adjusted annually based on new information and as related technology and processing methods change. Recovery adjustments will typically result in a future impact to the value of the material removed from the stockpiles at a revised weighted-average cost per pound of recoverable copper. For example, an increase in recovery rates increases recoverable copper in the leach stockpiles resulting in a lower weighted-average cost per pound of recoverable copper and a decrease in recovery rates decreases recoverable copper in the leach stockpiles and results in a higher weighted-average cost per pound of recoverable copper.

Based on an annual review of mill and leach stockpiles, FCX increased its estimated consolidated recoverable copper in certain leach stockpiles, net of joint venture interests, by 164 million pounds in 2024 and 73 million pounds in 2023. These revised estimates did not have a material impact on the weighted-average cost per pound of recoverable copper or FCX’s consolidated site production and delivery costs in 2024 or 2023.


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Property, Plant, Equipment and Mine Development Costs.  Property, plant, equipment and mine development costs are carried at cost. Mineral exploration costs, as well as drilling and other costs incurred for the purpose of converting mineral resources to proven and probable mineral reserves or identifying new mineral resources at development or production stage properties, are charged to expense as incurred. Development costs are capitalized beginning after proven and probable mineral reserves have been established. Development costs include costs incurred resulting from mine pre-production activities undertaken to gain access to proven and probable mineral reserves, including shafts, adits, drifts, ramps, permanent excavations, infrastructure and removal of overburden. For underground mines certain costs related to panel development, such as undercutting and drawpoint development, are also capitalized as mine development costs until production reaches sustained design capacity for the mine. After reaching design capacity, the underground mine transitions to the production phase and panel development costs are allocated to inventory and included as a component of production and delivery costs. Additionally, interest expense allocable to the cost of developing mines and to constructing new facilities is capitalized until assets are ready for their intended use.

Expenditures for replacements and improvements are capitalized. Costs related to periodic scheduled maintenance (i.e., turnarounds) are charged to expense as incurred. Depreciation for mining and milling life-of-mine assets, infrastructure and other common costs is determined using the unit-of-production (UOP) method based on total estimated recoverable proven and probable copper reserves (for primary copper mines) and proven and probable molybdenum reserves (for primary molybdenum mines). Development costs and acquisition costs for proven and probable mineral reserves that relate to a specific ore body are depreciated using the UOP method based on estimated recoverable proven and probable mineral reserves for the ore body benefited. Depreciation, depletion and amortization using the UOP method is recorded upon extraction of the recoverable copper or molybdenum from the ore body or production of finished goods (as applicable), at which time it is allocated to inventory cost and then included as a component of production and delivery costs. Other assets are depreciated on a straight-line basis over estimated useful lives for the related assets of up to 50 years for buildings and 3 to 50 years for machinery and equipment, and mobile equipment.

Included in property, plant, equipment and mine development costs is value beyond proven and probable mineral reserves (VBPP), primarily resulting from FCX’s acquisition of FMC. The concept of VBPP may be interpreted differently by different mining companies. FCX’s VBPP is attributable to (i) measured and indicated mineral resources that FCX believes could be brought into production with the establishment or modification of required permits and should market conditions and technical assessments warrant, (ii) inferred mineral resources and (iii) exploration potential.

Carrying amounts assigned to VBPP are not charged to expense until the VBPP becomes associated with additional proven and probable mineral reserves and the reserves are produced or the VBPP is determined to be impaired. Additions to proven and probable mineral reserves for properties with VBPP will carry with them the value assigned to VBPP at the date acquired, less any impairment amounts. Refer to Note 3 for further discussion.

Impairment of Long-Lived Mining Assets.  FCX assesses the carrying values of its long-lived mining assets for impairment when events or changes in circumstances indicate that the related carrying amounts of such assets may not be recoverable. In evaluating long-lived mining assets for recoverability, estimates of pre-tax undiscounted future cash flows of FCX’s individual mines are used. An impairment is considered to exist if total estimated undiscounted future cash flows are less than the carrying amount of the asset. Once it is determined that an impairment exists, an impairment loss is measured as the amount by which the asset carrying value exceeds its fair value. The estimated undiscounted cash flows used to assess recoverability of long-lived assets and to measure the fair value of FCX’s mining operations are derived from current business plans, which are developed using near-term price forecasts reflective of the current price environment and management’s projections for long-term average metal prices. In addition to near- and long-term metal price assumptions, other key assumptions include estimates of commodity-based and other input costs; proven and probable mineral reserves estimates, including the timing and cost to develop and produce the reserves; VBPP estimates; and the use of appropriate discount rates in the measurement of fair value. FCX believes its estimates and models used to determine fair value are similar to what a market participant would use. As quoted market prices are unavailable for FCX’s individual mining operations, fair value is determined through the use of after-tax discounted estimated future cash flows (i.e., Level 3 measurement).
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Deferred Mining Costs.  Stripping costs (i.e., the costs of removing overburden and waste material to access mineral deposits) incurred during the production phase of an open-pit mine are considered variable production costs and are included as a component of inventory produced during the period in which stripping costs are incurred. Major development expenditures, including stripping costs to prepare unique and identifiable areas outside the current mining area for future production that are considered to be pre-production mine development, are capitalized and amortized using the UOP method based on estimated recoverable proven and probable mineral reserves for the ore body benefited. However, where a second or subsequent pit or major expansion is considered to be a continuation of existing mining activities, stripping costs are accounted for as a current production cost and a component of the associated inventory.

Environmental Obligations. Environmental expenditures are charged to expense or capitalized, depending upon their future economic benefits. Accruals for such expenditures are recorded when it is probable that obligations have been incurred and the costs can be reasonably estimated. Environmental obligations attributed to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) or analogous state programs are considered probable when a claim is asserted, or is probable of assertion, and FCX, or any of its subsidiaries, have been associated with the site. Other environmental remediation obligations are considered probable based on specific facts and circumstances. FCX’s estimates of these costs are based on an evaluation of various factors, including currently available facts, existing technology, presently enacted laws and regulations, remediation experience, whether or not FCX is a potentially responsible party (PRP) and the ability of other PRPs to pay their allocated portions. With the exception of those obligations assumed in the acquisition of FMC that were initially recorded at estimated fair values (refer to Note 10 for further discussion), environmental obligations are recorded on an undiscounted basis. Where the available information is sufficient to estimate the amount of the obligation, that estimate has been used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than any other, the lower end of the range has been used. Possible recoveries of some of these costs from other parties are not recognized in the consolidated financial statements until they become probable. Legal costs associated with environmental remediation (such as fees to third-party legal firms for work relating to determining the extent and type of remedial actions and the allocation of costs among PRPs) are included as part of the estimated obligation.

Environmental obligations assumed in the 2007 acquisition of FMC, which were initially recorded at fair value and estimated on a discounted basis, are accreted to full value over time through charges to interest expense. Adjustments arising from changes in amounts and timing of estimated costs and settlements may result in increases and decreases in these obligations and are calculated in the same manner as they were initially estimated. Unless these adjustments qualify for capitalization, changes in environmental obligations are charged to operating income when they occur.

FCX performs a comprehensive review of its environmental obligations annually and also reviews changes in facts and circumstances associated with these obligations at least quarterly.

Asset Retirement Obligations.  FCX records the fair value of estimated AROs associated with tangible long-lived assets in the period incurred. AROs associated with long-lived assets are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. These obligations, which are initially estimated based on discounted cash flow estimates, are accreted to full value over time through charges to production and delivery costs. In addition, asset retirement costs (ARCs) are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s useful life.

For mining operations, reclamation costs for disturbances are recognized as an ARO and as a related ARC in the period of the disturbance and depreciated primarily on a UOP basis. FCX’s AROs for mining operations consist primarily of costs associated with mine reclamation and closure activities. These activities, which are site specific, generally include costs for earthwork, revegetation, water treatment and demolition.

For non-operating properties and operating mines whose reclamation-related assets have been fully depreciated, changes to the ARO are recorded in production and delivery costs.

At least annually, FCX reviews its ARO estimates for changes in the projected timing of certain reclamation and closure/restoration costs, changes in cost estimates and additional AROs incurred during the period. Refer to Note 10 for further discussion.

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Revenue Recognition.  FCX recognizes revenue for its products upon transfer of control in an amount that reflects the consideration it expects to receive in exchange for those products. Transfer of control is in accordance with the terms of customer contracts, which is generally upon shipment or delivery of the product. While payment terms vary by contract, terms generally include payment to be made within 30 days, but not longer than 60 days. Certain of FCX’s concentrate and cathode sales contracts also provide for provisional pricing, which is accounted for as an embedded derivative (refer to Note 12 for further discussion). For provisionally priced sales, 90% to 100% of the provisional invoice amount is collected upon shipment or within 20 days, and final balances are settled in a contractually specified future month (generally one to four months from the shipment date) based on quoted monthly average copper settlement prices on the London Metal Exchange (LME) or the Commodity Exchange Inc. (COMEX), and quoted monthly average London Bullion Market Association (London) PM gold prices.

FCX’s product revenues are also recorded net of treatment charges, royalties and export duties. Moreover, because a portion of the metals contained in copper concentrate is unrecoverable as a result of the smelting process, FCX’s revenues from concentrate sales are also recorded net of allowances based on the quantity and value of these unrecoverable metals. These allowances are a negotiated term of FCX’s contracts and vary by customer. Treatment and refining charges represent payments or price adjustments to smelters and refiners that are generally fixed. Refer to Note 14 for a summary of revenue by product type.

Gold sales are priced according to individual contract terms, generally the average London PM gold price for a specified month near the month of shipment.

The majority of FCX’s molybdenum sales are priced based on the Platts Metals Daily Molybdenum Dealer Oxide weekly average price, plus conversion premiums for products that undergo additional processing, such as ferromolybdenum and molybdenum chemical products, for the month prior to the month of shipment.

Stock-Based Compensation. Compensation costs for share-based payments to employees are measured at fair value and charged to expense over the requisite service period for awards that are expected to vest. The fair value of stock options is determined using the Black-Scholes-Merton option valuation model. The fair value for stock-settled restricted stock units (RSUs) is based on FCX’s stock price on the date of grant. Shares of common stock are issued at the vesting date for stock-settled RSUs. The fair value of performance share units (PSUs) are determined using FCX’s stock price and a Monte-Carlo simulation model. The fair value for liability-classified awards (i.e., cash-settled RSUs) is remeasured each reporting period using FCX’s stock price. FCX has elected to recognize compensation costs for stock option awards that vest over several years on a straight-line basis over the vesting period, and for RSUs using the graded-vesting method over the vesting period. Refer to Note 8 for further discussion.

Earnings Per Share.  FCX calculates its basic net income per share of common stock under the two-class method and calculates its diluted net income per share of common stock using the more dilutive of the two-class method or the treasury-stock method. Basic net income per share of common stock was computed by dividing net income attributable to common stockholders (after deducting undistributed dividends and earnings allocated to participating securities) by the weighted-average shares of common stock outstanding during the year. Diluted net income per share of common stock was calculated by including the basic weighted-average shares of common stock outstanding adjusted for the effects of all potential dilutive shares of common stock, unless their effect would be antidilutive.

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Reconciliations of net income and weighted-average shares of common stock outstanding for purposes of calculating basic and diluted net income per share for the years ended December 31 follow:
 202420232022 
Net income$4,399 $3,751 $4,479 
Net income attributable to noncontrolling interests(2,510)(1,903)(1,011)
Undistributed dividends and earnings allocated to participating securities(6)(6)(7)
Net income attributable to common stockholders$1,883 $1,842 $3,461 
(shares in millions)
Basic weighted-average shares of common stock outstanding1,438 1,434 1,441 
Add shares issuable upon exercise or vesting of dilutive stock options, PSUs and RSUs7 9 

10 
Diluted weighted-average shares of common stock outstanding1,445 1,443 1,451 
Net income per share attributable to common stockholders:
Basic$1.31 $1.28 $2.40 
Diluted$1.30 $1.28 $2.39 

Outstanding stock options with exercise prices greater than the average market price of FCX’s common stock during the year are excluded from the computation of diluted net income per share of common stock. Excluded shares of common stock associated with outstanding stock options totaled less than 1 million shares in 2024 and 2023 and 1 million shares in 2022.

Global Intangible Low-Taxed Income (GILTI). FCX has elected to treat taxes due on future U.S. inclusions in taxable income related to GILTI as a current period expense when incurred.

New Accounting Standards. We did not adopt any new accounting standards in 2024 that had a material impact on our consolidated financial statements.

Segment Reporting. In November 2023, the Financial Accounting Standards Board (FASB) issued an accounting standards update (ASU) related to segment reporting that requires disclosure of significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, the title and position of the CODM, and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. This ASU is effective for FCX’s consolidated financial statements for the year ended December 31, 2024, and subsequent interim consolidated financial statements, and did not materially impact FCX’s segment reporting as presented within Note 14.

Income Taxes. In December 2023, the FASB issued an ASU requiring enhancements to disclosures related to income taxes, including the rate reconciliation and information on income taxes paid. This ASU is effective for FCX’s consolidated financial statements for the year ended December 31, 2025.

Disaggregation of Expenses. In November 2024, the FASB issued an ASU requiring entities to provide disaggregated disclosures of specified categories of expenses that are included in relevant line items on the face of the income statement, including: purchases of inventory, employee compensation, depreciation, intangible asset amortization and depletion. This ASU is effective for FCX’s consolidated financial statements for the year ended December 31, 2027, and subsequent interim consolidated financial statements.

Subsequent Events. FCX evaluated events after December 31, 2024, and through the date the consolidated financial statements were issued, and determined any events or transactions occurring during this period that would require recognition or disclosure are appropriately addressed in these consolidated financial statements.

NOTE 2.  OWNERSHIP IN SUBSIDIARIES AND JOINT VENTURES
Ownership in Subsidiaries.  FCX owns 100% of FMC. FMC produces copper and molybdenum from mines in North America and South America. At December 31, 2024, FMC’s operating mines in North America were Morenci, Bagdad, Safford (including Lone Star), Sierrita and Miami located in Arizona; Tyrone and Chino located in New Mexico; and Henderson and Climax located in Colorado. FMC has a 72% interest in Morenci (refer to “Joint Ventures. Sumitomo and SMM Morenci, Inc.”) and owns 100% of the other North America mines. At December 31,
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2024, operating mines in South America were Cerro Verde (55.08% owned - refer to “Cerro Verde” below) located in Peru and El Abra (51% owned) located in Chile. At December 31, 2024, FMC’s net assets totaled $17.4 billion and its accumulated deficit totaled $13.5 billion. FCX had no loans to FMC outstanding at December 31, 2024 and 2023.

FCX owns 48.76% of PT-FI (refer to “PT-FI Divestment” below). At December 31, 2024, PT-FI’s net assets totaled $16.6 billion and its retained earnings totaled $12.1 billion. FCX had no loans to PT-FI outstanding at December 31, 2024 and 2023.

FCX owns 100% of Atlantic Copper (FCX’s smelting and refining unit in Spain). At December 31, 2024, Atlantic Copper’s net assets totaled $132 million and its accumulated deficit totaled $407 million. FCX had loans to Atlantic Copper outstanding totaling $644 million at December 31, 2024, and $611 million at December 31, 2023.

Cerro Verde. In September 2024, FCX purchased 5.3 million shares of Cerro Verde common stock for a total cost of $210 million, increasing FCX’s ownership interest in Cerro Verde to 55.08% from 53.56%. As a result of the transaction, the carrying value of Cerro Verde’s noncontrolling interest was reduced by $90 million, with $125 million recorded to capital in excess to par value, including a $5 million deferred tax impact.

PT-FI Divestment. On December 21, 2018, FCX completed the transaction with the Indonesia government regarding PT-FI’s long-term mining rights and share ownership (the 2018 Transaction). Pursuant to the divestment agreement and related documents, PT Mineral Industri Indonesia (MIND ID), an Indonesia state-owned enterprise, acquired all of Rio Tinto plc’s (Rio Tinto) interests associated with its joint venture with PT-FI (the former Rio Tinto Joint Venture) and 100% of FCX’s interests in PT Indonesia Papua Metal Dan Mineral (PTI).

In connection with the 2018 Transaction, PT-FI acquired all of the common stock of PT Rio Tinto Indonesia that held the former Rio Tinto Joint Venture interest. After the 2018 Transaction, MIND ID’s (26.24%) and PTI’s (25.00%) collective share ownership of PT-FI totals 51.24% and FCX’s share ownership totals 48.76%. The arrangements provide for FCX and the other pre-transaction PT-FI shareholders (i.e., MIND ID) to retain the economics of the revenue and cost sharing arrangements under the former Rio Tinto Joint Venture. As a result, FCX’s economic interest, including the attribution of net income or loss and dividends paid, in PT-FI approximated 81% through 2022 and is 48.76% in 2023 and thereafter (see “Attribution of PT-FI Net Income or Loss” below).

FCX, PT-FI, PTI and MIND ID entered into a shareholders agreement (the PT-FI Shareholders Agreement), which includes provisions related to the governance and management of PT-FI. FCX considered the terms of the PT-FI Shareholders Agreement and related governance structure, including whether MIND ID has substantive participating rights, and concluded that FCX has retained control and would continue to consolidate PT-FI in its financial statements following the 2018 Transaction. Among other terms, the governance arrangements under the PT-FI Shareholders Agreement transfers control over the management of PT-FI’s mining operations to an operating committee, which is controlled by FCX. Additionally, as discussed above, the existing PT-FI shareholders retained the economics of the revenue and cost sharing arrangements under the former Rio Tinto Joint Venture, so that FCX’s economic interest in the project through 2041 will not be significantly affected by the 2018 Transaction. FCX believes its conclusion to continue to consolidate PT-FI in its financial statements is in accordance with the U.S. Securities and Exchange Commission (SEC) Regulation S-X, Rule 3A-02 (a), which provides for situations in which consolidation of an entity, notwithstanding the lack of majority ownership, is necessary to present fairly the financial position and results of operations of the registrant, because of the existence of a parent-subsidiary relationship by means other than recorded ownership of voting stock.

Attribution of PT-FI Net Income or Loss. FCX concluded that the attribution of PT-FI’s net income or loss from December 21, 2018 (the date of the divestment transaction), through December 31, 2022 (the Initial Period), should be based on FCX’s and MIND ID’s economic interest, as previously discussed. PT-FI’s cumulative net income during the Initial Period totaled $6.0 billion, of which $4.9 billion was attributed to FCX.

Beginning January 1, 2023, the attribution of PT-FI’s net income or loss is based on equity ownership percentages (48.76% for FCX, 26.24% for MIND ID and 25.00% for PTI), except for net income in 2023 associated with the sale of approximately 190,000 ounces of gold because PT-FI did not achieve the Gold Target (as defined in the PT-FI Shareholders Agreement), and net income in 2024 associated with the closure of its 2021 corporate income tax audit and resolution of the framework for Indonesia disputed tax matters (refer to Note 9), which were attributed approximately 81% to FCX. For all of its other partially owned consolidated subsidiaries, FCX attributes net income or loss based on equity ownership percentages.

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Joint Ventures. 
Sumitomo and SMM Morenci, Inc. FMC owns a 72% undivided interest in Morenci via an unincorporated joint venture. The remaining 28% is owned by Sumitomo (15%) and SMM Morenci, Inc. (13%). Each partner takes in kind its share of Morenci’s production. FMC purchased 15 million pounds during 2024 and 46 million pounds during 2023 of Morenci’s copper cathode from Sumitomo and SMM Morenci, Inc. at market prices for $63 million and $177 million, respectively. FMC had receivables from Sumitomo and SMM Morenci, Inc. totaling $23 million at December 31, 2024, and $17 million at December 31, 2023.

PT Smelting. PT Smelting is an Indonesia company that owns a copper smelter and refinery in Gresik, Indonesia. In 1996, PT-FI entered into a joint venture and shareholder agreement with Mitsubishi Materials Corporation (MMC) to jointly construct the PT Smelting facilities. PT Smelting commenced operations in 1999. In December 2023, PT Smelting completed the expansion of its capacity by 30% to process approximately 1.3 million metric tons of copper concentrate per year. The project was funded by PT-FI with loans totaling $254 million that converted to equity effective June 30, 2024, increasing PT-FI’s common stock ownership in PT Smelting to 66% from 39.5%. MMC owns the remaining 34% of PT Smelting’s outstanding common stock and serves as the operator of the facilities.

FCX has determined that PT Smelting is a variable interest entity, however, as mutual consent of both PT-FI and MMC is required to make the decisions that most significantly impact the economic performance of PT Smelting, PT-FI is not the primary beneficiary. As PT-FI has the ability to exercise significant influence over PT Smelting, PT-FI is continuing to account for its investment in PT Smelting under the equity method (refer to Note 4).

PT-FI’s maximum exposure to loss is its investment in PT Smelting (refer to Note 4). PT-FI’s equity in PT Smelting’s earnings totaled $8 million in 2024, $10 million in 2023 and $24 million in 2022.

Beginning January 1, 2023, PT-FI’s commercial arrangement with PT Smelting changed from a copper concentrate sales agreement to a tolling arrangement. Under this arrangement, PT-FI pays PT Smelting a tolling fee to smelt and refine its copper concentrate and PT-FI retains title to all products for sale to third parties (i.e., there are no further sales from PT-FI to PT Smelting). PT-FI recorded tolling-related charges of $326 million in 2024 and $183 million in 2023.

NOTE 3.  PROPERTY, PLANT, EQUIPMENT AND MINE DEVELOPMENT COSTS, NET
The components of net property, plant, equipment and mine development costs follow:
 December 31,
 20242023
Proven and probable mineral reserves$7,159 $7,160 
VBPP358 359 
Mine development and other12,828 12,265 
Buildings and infrastructure10,667 10,165 
Machinery and equipment16,337 15,246 
Mobile equipment5,597 4,986 
Construction in progress9,364 6,945 
Oil and gas properties27,485 27,441 
Total89,795 84,567 
Accumulated depreciation, depletion and amortizationa
(51,281)(49,272)
Property, plant, equipment and mine development costs, net$38,514 $35,295 
a.Includes accumulated amortization for oil and gas properties of $27.4 billion at December 31, 2024 and 2023.

FCX recorded $1.6 billion for VBPP in connection with its 2007 acquisition of FMC (excluding $0.6 billion associated with mining operations that were subsequently sold) and transferred $0.8 billion to proven and probable mineral reserves through 2024 (approximately $1 million in both 2024 and 2023). Cumulative impairments of and adjustments to VBPP total $0.5 billion, which were primarily recorded in 2008.

Capitalized interest, which primarily related to FCX’s mining operations’ capital projects, including the construction and development of PT-FI’s new downstream processing facilities, totaled $391 million in 2024, $267 million in 2023 and $150 million in 2022.

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During the three-year period ended December 31, 2024, no material impairments of FCX’s long-lived mining assets were recorded.

NOTE 4.  OTHER ASSETS
The components of other assets follow:
 December 31,
 20242023
Intangible assetsa
$428 $422 
Legally restricted trust assetsb
217 212 
Disputed tax assessments:c
Cerro Verde275 274 
PT-FI10 10 
Investments:  
PT Smeltingd
354 123 
Fixed income, equity securities and other102 84 
Restricted time depositse
100 97 
Cloud computing arrangements151 76 
Long-term receivable for taxesf
43 70 
Long-term employee receivables24 26 
Prepaid rent and deposits9 39 
Loans to PT Smelting for expansiond
— 233 
Contingent consideration associated with sales of assetsg
— 38 
Other100 106 
Total other assets$1,813 $1,810 
a.Indefinite-lived intangible assets totaled $214 million at December 31, 2024 and 2023. Definite-lived intangible assets totaled $214 million at December 31, 2024, and $208 million at December 31, 2023, which were net of accumulated amortization totaling $46 million and $43 million, respectively.
b.Reflects amounts held in trusts for AROs related to properties in New Mexico (refer to Note 10).
c.Refer to Note 10.
d.Refer to Note 2.
e.Relates to PT-FI’s regulatory commitments (refer to Notes 10 and 12).
f.Includes tax overpayments and refunds not expected to be realized within the next 12 months.
g.Refer to Note 13.

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NOTE 5.  ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The components of accounts payable and accrued liabilities follow:
 December 31,
 20242023
Accounts payable$2,789 $2,466 
Salaries, wages and other compensation361 343 
Accrued interesta
135 146 
Pension, postretirement, postemployment and other employee benefitsb
128 129 
Leasesb,c
98 84 
Deferred revenue91 161 
Accrued taxes, other than income taxes81 88 
Community development programs75 58 
PT-FI administrative fined
59 55 
PT-FI contingenciese
49 67 
MIND ID indemnificationf
49 — 
Litigation accruals34 51 
Other108 81 
Total accounts payable and accrued liabilities$4,057 $3,729 
a.Third-party interest paid, net of capitalized interest, was $206 million in 2024, $419 million in 2023 and $417 million in 2022.
b.Refer to Note 7 for long-term portion.
c.Refer to Note 11.
d.Refer to Note 10.
e.Primarily reflects Indonesia tax matters. Refer to Note 10.
f.Refer to Note 11. At December 31, 2023, the MIND ID indemnification balance was included in other long-term liabilities (refer to Note 7).
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NOTE 6.  DEBT
FCX’s debt at December 31, 2024, is net of reductions of $58 million ($67 million at December 31, 2023) for unamortized net discounts and unamortized debt issuance costs. The components of debt follow:
 December 31,
 20242023
Revolving credit facilities:
FCX$— $— 
PT-FI250 — 
Cerro Verde— — 
Senior notes and debentures:  
Issued by FCX:
4.55% Senior Notes due 2024
— 730 
5.00% Senior Notes due 2027
449 448 
4.125% Senior Notes due 2028
484 483 
4.375% Senior Notes due 2028
431 430 
5.25% Senior Notes due 2029
469 468 
4.25% Senior Notes due 2030
447 446 
4.625% Senior Notes due 2030
589 588 
5.40% Senior Notes due 2034
724 723 
5.450% Senior Notes due 2043
1,688 1,689 
Issued by PT-FI:
4.763% Senior Notes due 2027
747 746 
5.315% Senior Notes due 2032
1,491 1,490 
6.200% Senior Notes due 2052
745 744 
Issued by FMC:
7 1/8% Debentures due 2027
115 115 
9 1/2% Senior Notes due 2031119 121 
6 1/8% Senior Notes due 2034119 118 
Other 81 83 
Total debt8,948 9,422 
Less current portion of debt(41)(766)
Long-term debt$8,907 $8,656 

Revolving Credit Facilities.
FCX. FCX and PT-FI have a $3.0 billion, unsecured revolving credit facility that matures in October 2027. Under the terms of the revolving credit facility, FCX may obtain loans and issue letters of credit in an aggregate amount of up to $3.0 billion, with a $1.5 billion sublimit on the issuance of letters of credit and a $500 million limit on PT-FI’s borrowing capacity. At December 31, 2024, there were no borrowings and $7 million in letters of credit issued under FCX’s revolving credit facility. Interest on loans made under the revolving credit facility may, at the option of FCX or PT-FI, be determined based on the Secured Overnight Financing Rate (SOFR) plus a spread to be determined by reference to a grid based on FCX’s credit rating.

The revolving credit facility contains customary affirmative covenants and representations, and also contains various negative covenants that, among other things and subject to certain exceptions, restrict the ability of FCX’s subsidiaries that are not borrowers or guarantors to incur additional indebtedness (including guarantee obligations) and the ability of FCX or FCX’s subsidiaries to: create liens on assets; enter into sale and leaseback transactions; engage in mergers, liquidations and dissolutions; and sell assets. In addition, the revolving credit facility contains a total leverage ratio financial covenant.

PT-FI. At December 31, 2024, PT-FI had $250 million in borrowings outstanding under its $1.75 billion senior unsecured revolving credit facility that matures in November 2028. PT-FI’s revolving credit facility is available for its general corporate purposes, including to fund PT-FI’s projects related to its new downstream processing facilities. Interest on loans made under PT-FI’s revolving credit facility are determined based on the SOFR plus a margin.

PT-FI’s revolving credit facility contains customary affirmative covenants and representations and also contains standard negative covenants that, among other things, restrict, subject to certain exceptions, the ability of PT-FI to incur additional indebtedness; create liens on assets; enter into sale and leaseback transactions; sell assets; and modify or amend the shareholders agreement or related governance structure. The credit facility also contains
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financial covenants governing maximum total leverage and minimum interest expense coverage and other covenants addressing certain environmental and social compliance requirements.

Cerro Verde. At December 31, 2024, Cerro Verde had no borrowings outstanding under its $350 million senior unsecured revolving credit facility that matures in May 2027. Cerro Verde’s revolving credit facility contains customary representations and affirmative and negative covenants.

At December 31, 2024, FCX, PT-FI and Cerro Verde were in compliance with their respective credit facility’s covenants.

Senior Notes.
FCX. In November 2024, FCX repaid $0.7 billion for the balance of its maturing 4.55% Senior Notes.

In 2023, FCX purchased $0.2 billion aggregate principal amount of its senior notes in open-market transactions for a total cost of $0.2 billion and recorded gains on early extinguishment of debt of $10 million. In 2022, FCX purchased $1.1 billion aggregate principal amount of its senior notes in open market transactions for a total cost of $1.0 billion and recorded gains on early extinguishment of debt of $44 million. FCX has not purchased senior notes in open-market transactions since July 2023.

The senior notes listed below are redeemable in whole or in part, at the option of FCX, at specified redemption prices prior to the dates stated below and beginning on the dates stated below at 100% of principal.

Debt InstrumentDate
5.00% Senior Notes due 2027September 1, 2025
4.125% Senior Notes due 2028March 1, 2026
4.375% Senior Notes due 2028August 1, 2026
5.25% Senior Notes due 2029September 1, 2027

The senior notes listed below are redeemable in whole or in part, at the option of FCX, at a make-whole redemption price prior to the dates stated below, at specified redemption prices beginning on the dates stated below, and at 100% of principal two years before maturity.

Debt InstrumentDate
4.25% Senior Notes due 2030March 1, 2025
4.625% Senior Notes due 2030August 1, 2025

The senior notes listed below are redeemable in whole or in part, at the option of FCX, at a make-whole redemption price prior to the dates stated below and beginning on the dates stated below at 100% of principal.
Debt InstrumentDate
5.40% Senior Notes due 2034May 14, 2034
5.450% Senior Notes due 2043September 15, 2042

FCX’s senior notes contain limitations on liens and rank equally with FCX’s other existing and future unsecured and unsubordinated indebtedness.

PT-FI. In April 2022, PT-FI completed the sale of $3.0 billion aggregate principal amount of unsecured senior notes, consisting of $750 million of 4.763% Senior Notes due 2027, $1.5 billion of 5.315% Senior Notes due 2032 and $750 million of 6.200% Senior Notes due 2052. PT-FI used $0.6 billion of the net proceeds to repay the borrowings under its term loan and recorded a loss on early extinguishment of debt of $10 million in 2022. PT-FI used the remaining net proceeds to finance its downstream processing facilities.


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The senior notes listed below are redeemable in whole or in part, at the option of PT-FI, at a make-whole redemption price prior to the dates stated below and beginning on the dates stated below at 100% of principal.
Debt InstrumentDate
4.763% Senior Notes due 2027March 14, 2027
5.315% Senior Notes due 2032January 14, 2032
6.200% Senior Notes due 2052October 14, 2051

Maturities.  Maturities of debt instruments based on the principal amounts outstanding at December 31, 2024, total $41 million in 2025, $5 million in 2026, $1.3 billion in 2027, $1.2 billion in 2028, $477 million in 2029 and $6.0 billion thereafter.

NOTE 7. OTHER LIABILITIES, INCLUDING EMPLOYEE BENEFITS
The components of other liabilities follow:
 December 31,
 20242023
Leasesa
$692 $347 
Pension, postretirement, postemployment and other employment benefitsb
689 704 
Litigation accruals163 163 
Provision for tax positions136 174 
Social investment programs111 79 
Indemnification of MIND IDa
— 75 
Other96 106 
Total other liabilities$1,887 $1,648 
a.Refer to Note 5 for current portion and Note 11 for further discussion.
b.Refer to Note 5 for current portion.

Pension Plans.  Following is a discussion of FCX’s pension plans.

FMC Plans. FMC has U.S. trusteed, non-contributory pension plans covering some U.S. employees and some employees of its international subsidiaries hired before 2007. The applicable FMC plan design determines the manner in which benefits are calculated for any particular group of employees. Benefits are calculated based on final average monthly compensation and years of service or based on a fixed amount for each year of service. Non-bargained FMC employees hired after December 31, 2006, are not eligible to participate in the FMC U.S. pension plan. Effective September 1, 2020, the FMC Retirement Plan, the largest FMC plan, was amended such that participants no longer accrue any additional benefits.

FCX’s funding policy for these plans provides that contributions to pension trusts shall be at least equal to the minimum funding requirements of the Employee Retirement Income Security Act of 1974, as amended, for U.S. plans; or, in the case of international plans, the minimum legal requirements that may be applicable in the various countries. Additional contributions also may be made from time to time.

FCX’s primary investment objectives for the FMC plan assets held in a master trust (Master Trust) are to maintain funds sufficient to pay all benefit and expense obligations when due, minimize the volatility of the plan’s funded status to the extent practical, and to maintain prudent levels of risk consistent with the plan’s investment policy. The FMC plan assets are invested in a risk-mitigating portfolio, which is allocated among multiple fixed income managers. The current target allocation of the portfolio is long-duration credit (50%); long-duration U.S. government/credit (20%); core fixed income (22%); long-term U.S. Treasury Separate Trading of Registered Interest and Principal Securities (7%); and cash equivalents (1%).

The expected rate of return on plan assets is evaluated at least annually, taking into consideration asset allocation, historical and expected future performance on the types of assets held in the Master Trust, and the current economic environment. Based on these factors, FCX expects the pension assets will earn an average of 5.20% per annum beginning January 1, 2025, which is based on the target asset allocation and long-term capital market return expectations.

For estimation purposes, FCX assumes the long-term asset mix for these plans generally will be consistent with the current mix. Changes in the asset mix could impact the amount of recorded pension costs, the funded status of the
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plans and the need for future cash contributions. A lower-than-expected return on assets also would decrease plan assets and increase the amount of recorded pension costs in future years. When calculating the expected return on plan assets, FCX uses the market value of assets.

Among the assumptions used to estimate the pension benefit obligation is a discount rate used to calculate the present value of expected future benefit payments for service to date. The discount rate assumption for FCX’s U.S. plans is designed to reflect yields on high-quality, fixed-income investments for a given duration. The determination of the discount rate for these plans is based on expected future benefit payments together with the Mercer Yield Curve – Above Mean. The Mercer Yield Curve – Above Mean is constructed from the bonds in the Mercer Pension Discount Curve that have a yield higher than the regression mean yield curve. The Mercer Yield Curve – Above Mean consists of spot (i.e., zero coupon) interest rates at one-half-year increments for each of the next 30 years and is developed based on pricing and yield information for high-quality corporate bonds. Changes in the discount rate are reflected in FCX’s benefit obligation and, therefore, in future pension costs.

SERP Plan. FCX has an unfunded Supplemental Executive Retirement Plan (SERP) for its Chairman of the Board. The SERP provides for retirement benefits payable in the form of a joint and survivor annuity, life annuity or an equivalent lump sum. The participant has elected to receive an equivalent lump sum payment. The payment will equal a percentage of the participant’s highest average compensation for any consecutive three-year period during the five years immediately preceding the completion of 25 years of credited service. The SERP benefit will be reduced by the value of all benefits from current and former retirement plans (qualified and nonqualified) sponsored by FCX, by FM Services Company, FCX’s wholly owned subsidiary, or by any predecessor employer (including FCX’s former parent company), except for benefits produced by accounts funded exclusively by deductions from the participant’s pay.

PT-FI Plan. PT-FI has a defined benefit pension plan denominated in Indonesia rupiah covering substantially all of its Indonesia national employees. PT-FI funds the plan and invests the assets in accordance with Indonesia pension guidelines. The pension obligation was valued at an exchange rate of 16,081 rupiah to one U.S. dollar on December 31, 2024, and 15,339 rupiah to one U.S. dollar on December 31, 2023. Indonesia labor laws require that companies provide a minimum severance to employees upon employment termination based on the reason for termination and the employee’s years of service. PT-FI’s pension benefit obligation includes benefits determined in accordance with this law. PT-FI’s expected rate of return on plan assets is evaluated at least annually, taking into consideration its long-range estimated return for the plan based on the asset mix. Based on these factors, PT-FI expects its pension assets will earn an average of 7% per annum beginning January 1, 2025. The discount rate assumption for PT-FI’s plan is based on the Indonesia Government Security Yield Curve. Changes in the discount rate are reflected in PT-FI’s benefit obligation and, therefore, in future pension costs.

Plan Information. FCX uses a measurement date of December 31 for its plans. Information for qualified and non-qualified plans where the projected benefit obligations and the accumulated benefit obligations exceed the fair value of plan assets follows:
 December 31,
 20242023
Projected and accumulated benefit obligation$1,734 $1,828 
Fair value of plan assets1,379 1,475 


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Information on the qualified and non-qualified FCX (FMC and SERP plans) and PT-FI plans as of December 31 follows:
FCXPT-FI
 2024202320242023
Change in benefit obligation:    
Benefit obligation at beginning of year$1,880 $1,884 $221 $215 
Service cost16 15 12 11 
Interest cost93 98 14 14 
Actuarial (gains) losses(76)15 (3)3 
Foreign exchange losses (gains)— 1 (11)4 
Benefits and administrative expenses paid(133)(133)(23)(27)
Other— — 3 1 
Benefit obligation at end of year1,780 1,880 213 221 
Change in plan assets:    
Fair value of plan assets at beginning of year1,537 1,483 203 205 
Actual return on plan assets(31)121 1 11 
Employer contributionsa
63 65 14 9 
Foreign exchange gains (losses)— 1 (10)4 
Benefits and administrative expenses paid(133)(133)(23)(26)
Fair value of plan assets at end of year1,436 1,537 185 203 
Funded status$(344)$(343)$(28)$(18)
Accumulated benefit obligation$1,780 $1,878 $165 $182 
Weighted-average assumptions used to determine benefit obligations:    
Discount rate5.67 %5.15 %7.00 %6.75 %
Rate of compensation increaseN/AN/A4.00 %4.00 %
Balance sheet classification of funded status:    
Other assets$11 $9 $— $— 
Accounts payable and accrued liabilities(3)(3)— — 
Other liabilities(352)(349)(28)(18)
Total$(344)$(343)$(28)$(18)
a.Employer contributions for 2025 are currently expected to approximate $64 million for the FCX plans and $11 million for the PT-FI plan (based on a December 31, 2024, exchange rate of 16,081 Indonesia rupiah to one U.S. dollar).

The actuarial gain of $76 million in 2024 and loss of $15 million in 2023 for the FCX pension plans primarily resulted from the changes in the discount rate, which were 5.67% at December 31, 2024, 5.15% at December 31, 2023, and 5.41% at December 31, 2022.

The weighted-average assumptions used to determine net periodic benefit cost and the components of net periodic benefit cost for FCX’s pension plans for the years ended December 31 follow:
 202420232022
Weighted-average assumptions:a
   
Discount rate5.15 %5.41 %2.85 %
Expected return on plan assets5.75 %5.00 %3.00 %
Service cost$16 $15 $15 
Interest cost93 98 71 
Expected return on plan assets(86)(72)(62)
Amortization of net actuarial losses13 15 15 
Net periodic benefit cost$36 $56 $39 
a.The assumptions shown relate only to the FMC Retirement Plan.

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The weighted-average assumptions used to determine net periodic benefit cost and the components of net periodic benefit cost for PT-FI’s pension plan for the years ended December 31 follow:
 202420232022
Weighted-average assumptions:   
Discount rate6.75 %7.00 %6.50 %
Expected return on plan assets7.00 %7.00 %7.00 %
Rate of compensation increase4.00 %4.00 %4.00 %
Service cost$12 $11 $12 
Interest cost14 14 14 
Expected return on plan assets(13)(14)(15)
Amortization of prior service cost— 2 1 
Amortization of net actuarial gains(1)(1)(1)
Special termination benefit— 1 2 
Net periodic benefit cost$12 $13 $13 

The service cost component of net periodic benefit cost is included in operating income, and the other components are included in other income, net in the consolidated statements of income.

Included in accumulated other comprehensive loss are the following amounts that have not been recognized in net periodic pension cost as of December 31:
20242023
 
Before Taxes
After Taxes and Noncontrolling Interests
Before Taxes
After Taxes and Noncontrolling Interests
Net actuarial losses$421 $289 $382 $257 
Prior service costs(4)(4)(1)(2)
$417 $285 $381 $255 

Plan assets are classified within a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1), then to prices derived using significant observable inputs (Level 2) and the lowest priority to prices derived using significant unobservable inputs (Level 3).

A summary of the fair value for pension plan assets, including those measured at net asset value (NAV) as a practical expedient, associated with the FCX plans follows:
 Fair Value at December 31, 2024
 TotalNAVLevel 1Level 2Level 3
Commingled/collective funds:    
    Fixed income securities$395 $395 $— $— $— 
    Short-term investments37 37 — — — 
Fixed income:    
Corporate bonds624 — — 624 — 
Government bonds238 — — 238 — 
Private equity investments68 68 — — — 
Other investments57 — 1 56 — 
Total investments1,419 $500 $1 $918 $— 
Cash and receivables20 
Payables(3)
Total pension plan net assets$1,436 

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 Fair Value at December 31, 2023
 TotalNAVLevel 1Level 2Level 3
Commingled/collective funds:      
Fixed income securities$417 $417 $— $— $— 
Short-term investments24 24 — — — 
Fixed income:
Corporate bonds677 — — 677 — 
Government bonds276 — — 276 — 
Private equity investments67 67 — — — 
Other investments63 — 1 62 — 
Total investments1,524 $508 $1 $1,015 $— 
Cash and receivables17 
Payables(4)
Total pension plan net assets$1,537 

Following is a description of the pension plan asset categories included in the above tables and the valuation techniques used to measure fair value. There have been no changes to the techniques used to measure fair value.

Commingled/collective funds are managed by several fund managers and are valued at the NAV per unit of the fund. For most of these funds, the majority of the underlying assets are actively traded securities. These funds primarily require up to a two-business-day notice for redemptions.

Fixed income investments include corporate and government bonds held directly by the Master Trust. Fixed income securities are valued using a bid-evaluation price or a mid-evaluation price and, as such, are classified within Level 2 of the fair value hierarchy. A bid-evaluation price is an estimated price at which a dealer would pay for a security. A mid-evaluation price is the average of the estimated price at which a dealer would sell a security and the estimated price at which a dealer would pay for a security. These evaluations are based on quoted prices, if available, or models that use observable inputs.

Private equity investments are valued at NAV using information from general partners and have inherent restrictions on redemptions that may affect the ability to sell the investments at their NAV in the near term.

A summary of the fair value hierarchy for pension plan assets associated with the PT-FI plan follows:
 
Fair Value at December 31, 2024
 TotalLevel 1Level 2Level 3
Government bonds$96 $96 $— $— 
Common stocks53 53 — — 
Mutual funds12 12 — — 
Total investments161 $161 $— $— 
Cash and receivablesa
24 
Total pension plan net assets$185 

 
Fair Value at December 31, 2023
 TotalLevel 1Level 2Level 3
Government bonds$102 $102 $— $— 
Common stocks67 67 — — 
Mutual funds12 12 — — 
Total investments181 $181 $— $— 
Cash and receivablesa
22 
Total pension plan net assets$203 
a.Cash consists primarily of short-term time deposits.

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Following is a description of the valuation techniques used for pension plan assets measured at fair value associated with the PT-FI plan. There have been no changes to the techniques used to measure fair value.

Government bonds, common stocks and mutual funds are valued at the closing price reported on the active market on which the individual securities are traded and, as such, are classified within Level 1 of the fair value hierarchy.

The techniques described above may produce a fair value calculation that may not be indicative of NRV or reflective of future fair values. Furthermore, while FCX believes its valuation techniques are appropriate and consistent with those used by other market participants, the use of different techniques or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

The expected benefit payments for FCX’s and PT-FI’s pension plans follow:
FCX
PT-FIa
2025$126 $14 
2026190 27 
2027129 29 
2028129 31 
2029129 28 
2030 through 2034633 133 
a.Based on a December 31, 2024, exchange rate of 16,081 Indonesia rupiah to one U.S. dollar.

Postretirement and Other Benefits.  FCX also provides postretirement medical and life insurance benefits for certain U.S. employees and, in some cases, employees of certain international subsidiaries. These postretirement benefits vary among plans, and many plans require contributions from retirees. The expected cost of providing such postretirement benefits is accrued during the years employees render service.

The benefit obligation (funded status) for the postretirement medical and life insurance benefit plans consisted of a current portion of $5 million (included in accounts payable and accrued liabilities) and a long-term portion of $31 million (included in other liabilities) at December 31, 2024, and a current portion of $5 million and a long-term portion of $34 million at December 31, 2023.

FCX has a number of postemployment plans covering severance, long-term disability income, continuation of health and life insurance coverage for disabled employees or other welfare benefits. The accumulated postemployment benefit obligation consisted of a current portion of $7 million (included in accounts payable and accrued liabilities) and a long-term portion of $43 million (included in other liabilities) at December 31, 2024, and a current portion of $7 million and a long-term portion of $46 million at December 31, 2023.

FCX also sponsors a retirement savings plan for most of its U.S. employees. The plan allows employees to contribute a portion of their income in accordance with specified guidelines. The savings plan is a qualified 401(k) plan for all U.S. salaried and non-bargained hourly employees. Participants exercise control and direct the investment of their contributions and account balances among various investment options under the plan. FCX contributes to the plan and matches a percentage of employee contributions up to certain limits. For employees whose eligible compensation exceeds certain levels, FCX provides a nonqualified unfunded defined contribution plan, which had a liability balance of $69 million at December 31, 2024, and $62 million at December 31, 2023, all of which was included in other liabilities.

The costs charged to operations for the employee savings plan totaled $131 million in 2024, $119 million in 2023 and $101 million in 2022. FCX has other employee benefit plans, certain of which are related to FCX’s financial results, which are recognized in operating costs.

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NOTE 8. STOCKHOLDERS’ EQUITY AND STOCK-BASED COMPENSATION
FCX’s authorized shares of capital stock consists of 3.0 billion shares of common stock and 50 million shares of preferred stock.

Financial Policy. FCX’s financial policy, which was adopted by its Board of Directors (Board) in 2021, includes a base dividend and a performance-based payout framework, whereby up to 50% of available cash flows generated after planned capital spending and distributions to noncontrolling interests is allocated to shareholder returns and the balance to debt reduction and investments in value enhancing growth projects, subject to FCX maintaining its net debt at a level not to exceed the net debt target of $3.0 billion to $4.0 billion (excluding net project debt for PT-FI’s new downstream processing facilities). The Board reviews the structure of the performance-based payout framework at least annually.

Under its $5.0 billion share repurchase program, FCX has acquired a total of 49.0 million shares of common stock for a cost of $1.9 billion ($38.64 average cost per share), including 1.2 million shares of its common stock for a total cost of $59 million in 2024 and 35.1 million shares of its common stock for a total cost of $1.3 billion in 2022 (no purchases were made in 2023). As of February 14, 2025, FCX has $3.1 billion available for repurchases under the program.

On December 18, 2024, FCX declared quarterly cash dividends totaling $0.15 per share on its common stock (including a $0.075 per share base dividend and $0.075 per share variable dividend), which were paid on February 3, 2025, to common stockholders of record as of January 15, 2025.

The declaration and payment of dividends (base or variable) and timing and amount of any share repurchases are at the discretion of FCX’s Board and management, respectively, and are subject to a number of factors, including not exceeding FCX’s net debt target, capital availability, FCX’s financial results, cash requirements, global economic conditions, changes in laws, contractual restrictions and other factors deemed relevant by FCX’s Board or management, as applicable. FCX’s share repurchase program may be modified, increased, suspended or terminated at any time at the Board’s discretion.

Accumulated Other Comprehensive Loss. A summary of changes in the balances of each component of accumulated other comprehensive loss, net of tax, follows:
Defined Benefit PlansTranslation AdjustmentTotal
Balance at January 1, 2022$(398)$10 $(388)
Amounts arising during the perioda,b
61 — 61 
Amounts reclassifiedc
7 — 7 
Balance at December 31, 2022(330)10 (320)
Amounts arising during the perioda,b
41 — 41 
Amounts reclassifiedc
5 — 5 
Balance at December 31, 2023(284)10 (274)
Amounts arising during the perioda,b
(44)— (44)
Amounts reclassifiedc
4 — 4 
Balance at December 31, 2024$(324)$10 $(314)
a.Includes net actuarial gains (loss), net of noncontrolling interest, totaling $59 million for 2022, $38 million for 2023 and $(46) million for 2024.
b.Includes tax benefits totaling $2 million for 2022, 2023 and 2024.
c.Includes amortization primarily related to actuarial losses, net of taxes of less than $1 million for 2022, 2023 and 2024.


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Stock Award Plans.  FCX currently has awards outstanding under various stock-based compensation plans. The stockholder-approved 2016 Stock Incentive Plan (the 2016 Plan) provides for the issuance of stock options, stock appreciation rights, restricted stock, RSUs, PSUs and other stock-based awards for up to 72 million common shares. As of December 31, 2024, 15.0 million shares were available for grant under the 2016 Plan, and no shares were available under other plans.

Stock-Based Compensation Cost. Compensation cost charged against earnings for stock-based awards for the years ended December 31 follows:
202420232022
Selling, general and administrative expenses$65 $64 $57 
Production and delivery44 45 38 
Total stock-based compensation109 109 95 
Tax benefit and noncontrolling interests’ sharea
(4)(5)(4)
Impact on net income$105 $104 $91 
a. Charges in the U.S. are not expected to generate a future tax benefit.

Stock Options. Stock options granted under the plans generally expire 10 years after the date of grant and vest in one-third annual increments beginning one year from the date of grant. The award agreements provide that participants will receive the following year’s vesting upon retirement. Therefore, on the date of grant, FCX accelerates one year of amortization for retirement-eligible employees. The award agreements also provide for accelerated vesting upon certain qualifying terminations of employment within one year following a change of control. FCX has not granted stock options since 2021.

A summary of stock options outstanding as of December 31, 2024, and activity during the year ended December 31, 2024, follows:
Number of
Options		Weighted-
Average
Exercise Price
Per Share		Weighted-
Average
Remaining
Contractual
Term (years)		Aggregate
Intrinsic
Value
Balance at January 18,749,933 $15.63 
Exercised(3,140,886)18.13 
Balance at December 315,609,047 14.22 4.1$134 
Vested and exercisable at December 315,609,047 14.22 4.1$134 
The total intrinsic value of options exercised was $95 million during 2024, $52 million during 2023 and $148 million during 2022. The total fair value of options vested was less than $1 million during 2024, $3 million during 2023 and $23 million during 2022.

Stock-Settled PSUs and RSUs. Since 2014, FCX’s executive officers received annual grants of PSUs that vest after a three-year performance period. The total grant date target shares related to the PSU grants were 0.4 million for each of 2024, 2023 and 2022, of which the executive officers will earn (i) between 0% and 200% of the target shares based on achievement of financial metrics and (ii) may be increased or decreased up to 25% of the target shares based on FCX’s total shareholder return compared to the total shareholder return of a peer group. PSU awards for FCX’s executive officers who are retirement-eligible are non-forfeitable. As such, FCX charges the estimated fair value of the non-forfeitable PSU awards to expense at the time the financial and operational metrics are established, which is typically grant date. The fair value of PSU awards for FCX’s executive officers who are not retirement-eligible are charged to expense over the performance period.

FCX grants RSUs that vest over a period of three years or at the end of three years to certain employees. Some award agreements allow for participants to receive the following year’s vesting upon retirement. Therefore, on the date of grant of these RSU awards, FCX accelerates one year of amortization for retirement-eligible employees. FCX also grants RSUs to its directors, which vest on the first anniversary of the date of grant. The fair value of the RSUs is amortized over the vesting period or the period until the director becomes retirement eligible, whichever is shorter. Upon a director’s retirement, all of their unvested RSUs immediately vest. For retirement-eligible directors, the fair value of RSUs is recognized in earnings on the date of grant.

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The award agreements provide for accelerated vesting of all RSUs held by directors if there is a change of control (as defined in the award agreements) and for accelerated vesting of all RSUs held by employees if they experience a qualifying termination within one year following a change of control. Dividends attributable to RSUs and PSUs accrue and are paid if the awards vest. A summary of outstanding stock-settled RSUs and PSUs as of December 31, 2024, and activity during the year ended December 31, 2024, follows:
Number of AwardsWeighted-Average Grant-Date Fair Value Per AwardAggregate
Intrinsic
Value
Balance at January 15,699,575 $37.23  
Granted2,262,830 39.46  
Vested(2,224,239)34.37  
Forfeited(15,082)41.00  
Balance at December 315,723,084 39.21 $218 

The total fair value of stock-settled RSUs and PSUs granted was $92 million during 2024, $93 million during 2023 and $83 million during 2022. The total intrinsic value of stock-settled RSUs and PSUs vested was $84 million during 2024, $136 million during 2023 and $138 million during 2022. As of December 31, 2024, FCX had $27 million of total unrecognized compensation cost related to unvested stock-settled RSUs and PSUs expected to be recognized over approximately 1.1 years.

Cash-Settled RSUs. Cash-settled RSUs are similar to stock-settled RSUs but are settled in cash rather than in shares of common stock. These cash-settled RSUs generally vest over three years of service. Some award agreements allow for participants to receive the following year’s vesting upon retirement. Therefore, on the date of grant of these cash-settled RSU awards, FCX accelerates one year of amortization for retirement-eligible employees. The cash-settled RSUs are classified as liability awards, and the fair value of these awards is remeasured each reporting period until the vesting dates. The award agreements for cash-settled RSUs provide for accelerated vesting upon certain qualifying terminations of employment within one year following a change of control.

Dividends attributable to cash-settled RSUs accrue and are paid if the awards vest. A summary of outstanding cash-settled RSUs as of December 31, 2024, and activity during the year ended December 31, 2024, follows:
Number of AwardsWeighted-Average Grant-Date Fair Value Per AwardAggregate
Intrinsic
Value
Balance at January 1858,741 $40.23  
Granted626,050 39.58 
Vested(398,727)38.19 
Forfeited(22,578)40.72  
Balance at December 311,063,486 40.60 $40 

The total grant-date fair value of cash-settled RSUs was $25 million during 2024, $24 million during 2023 and $15 million during 2022. The intrinsic value of cash-settled RSUs vested was $15 million during 2024, $20 million during 2023 and $26 million during 2022. The accrued liability associated with cash-settled RSUs consisted of a current portion of $22 million (included in accounts payable and accrued liabilities) and a long-term portion of $8 million (included in other liabilities) at December 31, 2024, and a current portion of $19 million and a long-term portion of $7 million at December 31, 2023.


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Other Information. The following table includes amounts related to exercises of stock options and vesting of RSUs and PSUs during the years ended December 31:
 202420232022
FCX shares tendered or withheld to pay the exercise   
price and/or the statutory withholding taxesa
1,505,675 1,633,519 1,511,072 
Cash received from stock option exercises$29 $47 $125 
Actual tax benefit realized for tax deductions$5 $4 $13 
Amounts FCX paid for employee taxes$35 $50 $55 
a.Under terms of the related plans, upon exercise of stock options, vesting of stock-settled RSUs and payout of PSUs, employees may tender or have withheld FCX shares to pay the exercise price and/or required withholding taxes.

NOTE 9.  INCOME TAXES
Geographic sources of (losses) income before income taxes and equity in affiliated companies’ net earnings for the years ended December 31 follow:
 202420232022
U.S.$(547)$68 $840 
Foreign7,454 5,938 5,875 
Total$6,907 $6,006 $6,715 

Income taxes are provided on the earnings of FCX’s material foreign subsidiaries under the assumption that these earnings will be distributed. FCX has not provided deferred income taxes for other differences between the book and tax carrying amounts of its investments in material foreign subsidiaries as FCX considers its ownership positions to be permanent in duration, and quantification of the related deferred tax liability is not practicable. 

FCX’s provision for income taxes for the years ended December 31 follows:
 202420232022
Current income taxes:   
Federal$36 $5 $— 
State(1)(6)1 
Foreign(2,635)(2,087)(2,232)
Total current(2,600)(2,088)(2,231)
Deferred income taxes:   
Federal1 (50)(149)
State(1)(3)(6)
Foreign74 (320)(144)
Total deferred74 (373)(299)
Adjustments— 6 1 

Operating loss carryforwards3 185 262 
Provision for income taxes$(2,523)$(2,270)$(2,267)

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A reconciliation of the U.S. federal statutory tax rate to FCX’s effective income tax rate for the years ended December 31 follows:
 202420232022
 Amount%Amount%Amount%
U.S. federal statutory tax rate$(1,450)(21)%$(1,261)(21)%$(1,410)(21)%
Foreign tax credit expiration/ limitationa
(1,053)(15)(289)(5)(50)(1)
Valuation allowancea
898 13 119 2 65 — 
Withholding and other impacts on
foreign earnings(753)(11)(615)(10)(673)(10)
Effect of foreign rates different than the U.S.
federal statutory rate(373)(6)(313)(5)(314)(5)
PT-FI historical tax disputesb
185 2 — — (8)— 
Percentage depletion123 2 183 3 189 3 
State income taxes(52)(1)3 — (41)— 
Non-deductible permanent differences(41)— (68)(1)(29)— 
Uncertain tax positions5 — (28)(1)(17)— 
Other items, net(12)— (1)— 21 — 
Provision for income taxes$(2,523)(37)%$(2,270)(38)%$(2,267)(34)%
a.Refer to “Valuation Allowances” below.
b.Refer to “Indonesia Tax Matters” below.

FCX paid federal, state and foreign income taxes totaling $2.8 billion in 2024, $2.1 billion in 2023 and $3.1 billion in 2022. FCX received refunds of federal, state and foreign income taxes totaling $248 million in 2024, less than $1 million in 2023 and $46 million in 2022.

The components of deferred taxes follow:
 December 31,
 20242023
Deferred tax assets:  
Net operating losses$1,814 $1,761 
Accrued expenses1,657 1,390 
Foreign tax credits184 1,228 
Employee benefit plans76 78 
Other214 215 
Deferred tax assets3,945 4,672 
Valuation allowances(2,984)(3,894)
Net deferred tax assets961 778 
Deferred tax liabilities:  
Property, plant, equipment and mine development costs(4,193)(4,118)
Undistributed earnings(981)(911)
Other(155)(195)
Total deferred tax liabilities(5,329)(5,224)
Net deferred tax liabilities$(4,368)$(4,446)

Tax Attributes. At December 31, 2024, FCX had (i) U.S. foreign tax credits of $0.2 billion that will expire between 2025 and 2034, (ii) U.S. federal net operating losses (NOLs) of $6.0 billion, of which $0.7 billion can be carried forward indefinitely, with the remainder primarily expiring between 2036 and 2037, (iii) U.S. state NOLs of $10.6 billion, of which $3.5 billion can be carried forward indefinitely, with the remainder primarily expiring between 2025 and 2044, and (iv) Atlantic Copper NOLs of $0.5 billion that can be carried forward indefinitely.

Valuation Allowances. On the basis of available information at December 31, 2024, including positive and negative evidence, FCX has provided valuation allowances for certain of its deferred tax assets where it believes it is more-likely-than-not that some portion or all of such assets will not be realized. Valuation allowances totaled $3.0 billion at December 31, 2024, and covered all of FCX’s U.S. foreign tax credits and U.S. federal NOLs, substantially all of its U.S. state and foreign NOLs, as well as a portion of its U.S. federal, state and foreign deferred tax assets.
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The valuation allowance related to FCX’s U.S. foreign tax credits totaled $0.2 billion at December 31, 2024. FCX has operations in tax jurisdictions where statutory income taxes and withholding taxes are in excess of the U.S. federal income tax rate. Valuation allowances are recognized on foreign tax credits for which no benefit is expected to be realized.

The valuation allowance related to FCX’s U.S. federal, state and foreign NOLs totaled $1.8 billion and other deferred tax assets totaled $1.0 billion at December 31, 2024. NOLs and deferred tax assets represent future deductions for which a benefit will only be realized to the extent these deductions offset future income. FCX develops an estimate of which future tax deductions will be realized and recognizes a valuation allowance to the extent these deductions are not expected to be realized in future periods.

Valuation allowances will continue to be carried on U.S. foreign tax credits, U.S. federal, state and foreign NOLs and U.S. federal, state and foreign deferred tax assets, until such time that (i) FCX generates taxable income against which any of the assets, credits or NOLs can be used, (ii) forecasts of future income provide sufficient positive evidence to support reversal of the valuation allowances or (iii) FCX identifies a prudent and feasible means of securing the benefit of the assets, credits or NOLs that can be implemented.

The $0.9 billion net decrease in the valuation allowances during 2024 is primarily related to a decrease for expirations of U.S. foreign tax credits.

U.S. Inflation Reduction Act of 2022. The provisions of the U.S. Inflation Reduction Act of 2022 (the Act) became applicable to FCX on January 1, 2023. The Act includes, among other provisions, a new Corporate Alternative Minimum Tax (CAMT) of 15% on the adjusted financial statement income (AFSI) of corporations with average annual AFSI exceeding $1.0 billion over a three-year period.

In September 2024, the Internal Revenue Service (IRS) issued proposed regulations that provide guidance on the application of CAMT, which are not final and subject to change. Based on the proposed guidance released by the IRS, FCX determined that the provisions of the Act did not impact its financial results for the years 2024 or 2023.

Pillar Two of the Global Anti-Base Erosion Rules. In 2021, the Organisation for Economic Co-operation and Development (OECD) published a framework for Pillar Two of the Global Anti-Base Erosion Rules, which was designed to coordinate participating jurisdictions in updating the international tax system to ensure that large multinational companies pay a minimum level of income tax. Recommendations from the OECD regarding a global minimum income tax and other changes are being considered and/or implemented in jurisdictions where FCX operates. At current metals market prices, FCX does not expect enactment of the recommended framework in jurisdictions where it operates to materially impact its financial results.

Indonesia Tax Matters. During 2024, in conjunction with closure of PT-FI’s 2021 corporate income tax audit and resolution of Indonesia disputed tax matters, PT-FI recorded credits to net income of $215 million, including $199 million to provision for income taxes, $8 million to production and delivery and $8 million to interest expense, net.

Peru Tax Matters. Cerro Verde’s current mining stability agreement subjects it to a stable income tax rate of 32% through the expiration of the agreement on December 31, 2028. The enacted tax rate on dividend distributions, which is not stabilized by the agreement, is 5%.

Chile Tax Matters. Under the US-Chilean Tax Treaty, which became effective in 2024, FCX’s share of income from El Abra is subject to an income tax rate of 35%.

Effective January 1, 2024, mining royalty taxes in Chile consist of two main components: (i) profitability-based mining royalty rates on a sliding scale of 8% to 26% (depending on a defined operational margin) and (ii) an additional ad valorem royalty tax based on 1% of sales.

Uncertain Tax Positions. Tax positions reflected in the consolidated financial statements are, based on their technical merits, more-likely-than-not to be sustained upon examination by taxing authorities or have otherwise been effectively settled. Such tax positions reflect the largest amount of benefit, determined on a cumulative probability basis, that is more-likely-than-not to be realized upon settlement with the applicable taxing authority with full knowledge of all relevant information. FCX’s policy associated with uncertain tax positions is to record accrued
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interest in interest expense and accrued penalties in other income, net, rather than in the provision for income taxes.

A summary of the activities associated with FCX’s reserve for unrecognized tax benefits for the years ended December 31 follows.
202420232022
Balance at beginning of year$720 $810 $808 
Additions:
Prior year tax positions13 27 26 
Current year tax positions10 28 25 
Decreases:
Prior year tax positions(54)(13)(12)
Settlements with taxing authorities(492)(132)(37)
Lapse of statute of limitations(36)— — 
Balance at end of year$161 $720 $810 

The total amount of accrued interest and penalties associated with unrecognized tax benefits was $264 million at December 31, 2024, primarily relating to unrecognized tax benefits associated with royalties and the timing of advance payments, $536 million at December 31, 2023, and $551 million at December 31, 2022. Amounts include unpaid items on the consolidated balance sheet of $26 million at December 31, 2024, $33 million at December 31, 2023, and $36 million at December 31, 2022. Benefits (charges) for interest and penalties related to unrecognized tax benefits totaled $8 million in 2024, $(153) million in 2023 and $(7) million in 2022.

The reserve for unrecognized tax benefits of $161 million at December 31, 2024, included $153 million ($52 million net of income tax benefits and valuation allowances) that, if recognized, would reduce FCX’s provision for income taxes. Changes in the reserve for unrecognized tax benefits associated with current and prior-year tax positions were primarily related to uncertainties associated with FCX’s tax treatment of cost recovery methods, various non-deductible costs, and royalties and other mining taxes. There continues to be uncertainty related to the timing of settlements with taxing authorities, but if additional settlements are agreed upon during the year 2025, FCX could experience a change in its reserve for unrecognized tax benefits.

FCX or its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. The tax years for FCX’s major tax jurisdictions that remain subject to examination are as follows:
JurisdictionYears Subject to ExaminationAdditional Open Years
U.S. Federal—2021-2024
Indonesia 2017, 20202022-2024
Peru2020-20212017-2019, 2022-2024
Chile20232021-2022, 2024

NOTE 10.  CONTINGENCIES
Environmental. FCX’s operations are subject to various environmental laws and regulations that govern the generation, storage, treatment, transportation and disposal of hazardous substances; solid waste disposal; air emissions; wastewater discharges; remediation, restoration and reclamation of environmental contamination, including mine closures and reclamation; protection of endangered and threatened species and designation of critical habitats; and other related matters. FCX subsidiaries that operate in the U.S. also are subject to potential liabilities arising under CERCLA and similar state laws that impose responsibility on current and previous owners and operators of a facility for the remediation of hazardous substances released from the facility into the environment, including damages to natural resources, in some cases irrespective of when the damage to the environment occurred or who caused it. Remediation liability also extends to persons who arranged for the disposal of hazardous substances or transported the hazardous substances to a disposal site selected by the transporter. These liabilities are often shared on a joint and several basis, meaning that each responsible party is fully responsible for the remediation if some or all of the other historical owners or operators no longer exist, do not have the financial ability to respond or cannot be found. As a result, because of FCX’s acquisition of FMC, many of the subsidiary companies FCX now owns are responsible for a wide variety of environmental remediation projects throughout the U.S., and FCX expects to spend substantial sums annually for many years to address those
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remediation issues. Certain FCX subsidiaries have been advised by the U.S. Environmental Protection Agency (EPA), the Department of the Interior, the Department of Agriculture and various state agencies that, under CERCLA or similar state laws and regulations, they may be liable for costs of responding to environmental conditions at a number of sites that have been or are being investigated to determine whether releases of hazardous substances have occurred and, if so, to develop and implement remedial actions to address environmental concerns. FCX is also subject to claims where the release of hazardous substances is alleged to have caused natural resource damages (NRD) and to litigation by individuals allegedly exposed to hazardous substances. As of December 31, 2024, FCX had more than 80 active remediation projects, including NRD claims, in 20 U.S. states. The largest obligations discussed below account for approximately 85% of the total balance at December 31, 2024.

A summary of changes in FCX’s estimated environmental obligations for the years ended December 31 follows:
 202420232022
Balance at beginning of year$1,939 $1,740 $1,664 
Accretion expensea
131 119 110 
Net additionsb
82 195 43 
Spending(112)(115)(77)
Balance at end of year2,040 1,939 1,740 
Less current portion(131)(131)(125)
Long-term portion$1,909 $1,808 $1,615 
a.Represents accretion of the fair value of environmental obligations assumed in the acquisition of FMC, which were determined on a discounted cash flow basis.
b.Primarily reflects revisions for changes in the anticipated scope and timing of projects. See further discussion below.

Estimated future environmental cash payments (on an undiscounted and de-escalated basis) total $4.4 billion, including $131 million in 2025, $111 million in 2026, $122 million in 2027, $112 million in 2028, $77 million in 2029 and $3.8 billion thereafter. The amount and timing of these estimated payments will change as a result of changes in regulatory requirements, changes in scope and timing of remediation activities, the settlement of environmental matters and as actual spending occurs.

At December 31, 2024, FCX’s environmental obligations totaled $2.0 billion, including $1.9 billion recorded on a discounted basis for those obligations assumed in the FMC acquisition at fair value. FCX estimates it is reasonably possible that these obligations could range between $3.9 billion and $5.1 billion on an undiscounted and de-escalated basis.

At December 31, 2024, the most significant environmental obligations were associated with the Pinal Creek site in Arizona; the Newtown Creek site in New York City; historical smelter sites principally located in Arizona, Indiana, Kansas, Missouri, New Jersey, Oklahoma and Pennsylvania; and uranium mining sites in the western U.S. The recorded environmental obligations for these sites totaled $1.7 billion at December 31, 2024. FCX may also be subject to litigation brought by private parties, regulators and local governmental authorities related to these historical sites. A discussion of these sites follows.

Pinal Creek. The Pinal Creek site was listed under the Arizona Department of Environmental Quality’s (ADEQ) Water Quality Assurance Revolving Fund program in 1989 for contamination in the shallow alluvial aquifers within the Pinal Creek drainage near Miami, Arizona. Since that time, environmental remediation has been performed by members of the Pinal Creek Group, consisting of Freeport-McMoRan Miami Inc. (Miami), an indirect wholly owned subsidiary of FCX, and two other companies. Pursuant to a 2010 settlement agreement, Miami agreed to take full responsibility for future groundwater remediation at the Pinal Creek site, with limited exceptions. Remediation work consisting of groundwater extraction and treatment plus source control capping is expected to continue for many years. During 2023, FCX recorded adjustments to the Pinal Creek environmental obligation totaling $61 million associated with a refined engineering scope and cost estimate for work to be completed within the next several years. FCX’s environmental liability balance for this site was $517 million at December 31, 2024.

Newtown Creek. From the 1930s until 1964, Phelps Dodge Refining Corporation (PDRC), an indirect wholly owned subsidiary of FCX, operated a copper smelter, and from the 1930s until 1984, a copper refinery, on the banks of Newtown Creek (the creek), which is a 3.5-mile-long waterway that forms part of the boundary between Brooklyn and Queens in New York City. Heavy industrial uses on and around the creek and discharges from the City of New York’s sewer system over more than a century resulted in significant environmental contamination of the waterway. In 2010, EPA designated the creek as a Superfund site and identified PDRC, four other companies and the City of
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New York as potentially responsible parties (PRPs). The following year, PDRC and the four other companies (the Newtown Creek Group, NCG) and the City of New York entered an Administrative Order on Consent to perform a remedial investigation/feasibility study (RI/FS) to assess the nature and extent of environmental contamination in the creek and identify remedial options. EPA approved the final RI report in April 2023. The NCG’s FS work is ongoing. EPA currently expects to approve the final FS report by April 2028, although this timeframe may be further extended. EPA is also considering performing the FS evaluation and remedy selection by creek segment. At the agency’s request, the NCG prepared a focused feasibility study (FFS) for an early action remediation project focusing on the East Branch tributary of the creek. EPA approved the FFS report and, in January 2025, the agency issued a record of decision selecting an interim remedy for the East Branch. EPA has identified 30 PRPs for the site, including the NCG members and New York City, and invited all PRPs to participate in performing the East Branch remedial design. During 2023, FCX recorded adjustments to Newtown Creek environmental obligations totaling $64 million based on updated cost estimates from the draft early action FFS and no further adjustment was considered necessary based on the issuance of the 2025 record of decision. FCX’s environmental liability balance for this site was $452 million at December 31, 2024. The scope and design of the site remedy (or remedies), final costs of the site investigation and remediation, and allocation of costs among PRPs are uncertain and subject to change. Changes to the overall cost of this remedial obligation and the portion ultimately allocated to PDRC could be material to FCX.

Historical Smelter Sites. FCX subsidiaries and their predecessors at various times owned or operated copper, zinc and lead smelters or refineries in states including Arizona, Indiana, Kansas, Missouri, New Jersey, Oklahoma and Pennsylvania. For some of these former processing sites, certain FCX subsidiaries have been advised by EPA or state agencies that they may be liable for costs of investigating and, if appropriate, remediating environmental conditions associated with these former processing facilities. At other sites, certain FCX subsidiaries have entered into state voluntary remediation programs to investigate and, if appropriate, remediate on-site and off-site conditions associated with the facilities. The historical processing sites are in various stages of assessment and remediation. At some of these sites, disputes with local residents and elected officials regarding alleged health effects or the effectiveness of remediation efforts have resulted in litigation of various types, and similar litigation at other sites is possible.

From 1920 until 1986, United States Metals Refining Company (USMR), an indirect wholly owned subsidiary of FCX, owned and operated a copper smelter and refinery in the Borough of Carteret, New Jersey. Since the early 1980s, the site has been the subject of environmental investigation and remediation, under the direction and supervision of the New Jersey Department of Environmental Protection (NJDEP). On-site contamination is in the later stages of remediation. In 2012, after receiving a request from NJDEP, USMR also began investigating and remediating off-site properties, which is ongoing. As a result of off-site soil sampling in public and private areas near the former Carteret smelter, FCX established an environmental obligation for known and potential off-site environmental remediation; that work has been essentially completed at the end of 2024. Assessments of sediments in the adjacent Arthur Kill and possible remedial actions could result in additional adjustments to the related environmental obligation in future periods.

In January 2024, the EPA released guidance lowering the recommended screening levels for investigating lead-contaminated soils from 400 to 200 parts per million (ppm) or 100 ppm where there are other sources of lead exposure (such as lead-based paint that is common in older homes). Screening levels can be used to establish cleanup levels by some agencies and more stringent cleanup levels often lead to higher costs through exponential volume increases due to resulting expanded project footprints. In January 2025, EPA published its final toxicological assessment for inorganic arsenic, which may be used to calculate cleanup levels at state and federal remediation sites and may lead to regulatory guidance, rulemaking and other regulatory activities. FCX is working with state agencies to understand possible ramifications of this guidance on its projects. This EPA guidance and future changes to EPA’s lead and arsenic cleanup levels could result in increases to FCX’s environmental obligations for ongoing residential property cleanup projects near former smelter sites.

FCX’s environmental liability balance for historical smelter sites, including in the Borough of Carteret, New Jersey, was $266 million at December 31, 2024.

Uranium Mining Sites. During a period between 1940 and the early 1980s, certain FCX subsidiaries and their predecessors were involved in uranium exploration and mining in the western U.S., primarily on federal and tribal lands in the Four Corners region of the Southwest. Similar exploration and mining activities by other companies have also caused environmental impacts warranting remediation.

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In 2017, the Department of Justice, EPA, Navajo Nation, and two FCX subsidiaries reached an agreement regarding the financial contribution of the U.S. Government and the FCX subsidiaries and the scope of the environmental investigation and remediation work for 94 former uranium mining sites on tribal lands. Under the terms of the Consent Decree executed in May 2017, and approved by the U.S. District Court for the District of Arizona, the U.S. contributed $335 million into a trust fund to cover the government’s initial share of the costs, and
FCX’s subsidiaries are proceeding with the environmental investigation and remediation work at the 94 sites. The program is expected to take more than 20 years to complete. The Consent Decree excluded 23 former uranium mine sites at which an FCX subsidiary may also be potentially liable, but for which the U.S. recovered funds as part of a larger bankruptcy settlement with Tronox. In 2021, EPA informed an FCX subsidiary as well as two other federal entities that it does not expect to have funds sufficient to remediate all of the sites covered by the Tronox bankruptcy settlement. Based on information from EPA, it is currently considered unlikely that EPA will deplete the Tronox settlement funds in the near-term.

FCX is also conducting site surveys of historical uranium mining claims associated with FCX subsidiaries on non-tribal federal lands in the Four Corners region. Under a memorandum of understanding with the U.S. Bureau of Land Management (BLM), site surveys are being performed on approximately 15,000 mining claims, ranging from undisturbed claims to claims with mining features. Based on these surveys, BLM has issued no further action determinations for certain undisturbed claims. A similar agreement is in place with the U.S. Forest Service for mine features on U.S. Forest Service land. Either BLM or the U.S. Forest Service may request additional assessment or remediation activities for other claims with mining features. FCX will update this obligation when it has a sufficient number of remedy decisions from the BLM or the U.S. Forest Service to support a reasonably certain range of outcomes. FCX expects it will take several years to complete this work.

FCX’s environmental liability balance for the uranium mining sites was $473 million at December 31, 2024.

AROs. FCX’s ARO estimates are reflected on a third-party cost basis and are based on FCX’s legal obligation to retire tangible, long-lived assets. A summary of changes in FCX’s AROs for the years ended December 31 follows:
 202420232022
Balance at beginning of year$3,001 $3,043 $2,716 
Liabilities incurred16 18 9 
Revisions to cash flow estimates and settlements, net635 
a
54 381 
a
Accretion expense154 20 
b
134 
Spending(122)(134)(197)
Balance at end of year3,684 3,001 3,043 
Less current portion(189)(185)(195)
Long-term portion$3,495 $2,816 $2,848 
a.Primarily reflects adjustments for oil and gas properties, Sierrita, PT-FI, Climax and Henderson for the year 2024, and PT-FI, Morenci and Bagdad for the year 2022. See further discussion below.
b.Includes a $112 million adjustment at PT-FI to correct certain inputs in the historical PT-FI ARO model.

ARO costs may increase or decrease significantly in the future as a result of changes in regulations, changes in engineering designs and technology, permit modifications or updates, changes in mine plans, settlements, inflation or other factors and as reclamation (concurrent with mining operations or post mining) spending occurs. ARO activities and expenditures for mining operations generally are made over an extended period of time commencing near the end of the mine life; however, certain reclamation activities may be accelerated if legally required or if determined to be economically beneficial. For ARO activities and expenditures for oil and gas operations, the methods used or required to plug and abandon non-producing oil and gas wellbores; remove platforms, tanks, production equipment and flow lines; and restore wellsites could change over time.

Financial Assurance. New Mexico, Arizona, Colorado and other states, as well as U.S. regulations governing mine operations on federal land, require financial assurance to be provided for the estimated costs of mine reclamation and closure, including groundwater quality protection programs. FCX has satisfied financial assurance requirements by using a variety of mechanisms, primarily involving parent company performance guarantees and financial capability demonstrations, but also trust funds, surety bonds, letters of credit and other collateral. The applicable regulations specify financial strength tests that are designed to confirm a company’s or guarantor’s financial capability to fund estimated reclamation and closure costs. The amount of financial assurance FCX subsidiaries are required to provide will vary with changes in laws, regulations, reclamation and closure requirements, and cost
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estimates. At December 31, 2024, FCX’s financial assurance obligations associated with these U.S. mine closure and reclamation/restoration costs totaled $2.0 billion, of which $1.2 billion was in the form of guarantees issued by FCX and FMC. At December 31, 2024, FCX had trust assets totaling $0.2 billion (included in other assets), which are legally restricted to be used to satisfy its financial assurance obligations for its mining properties in New Mexico. In addition, FCX subsidiaries have financial assurance obligations for their oil and gas properties associated with plugging and abandoning wells and facilities totaling $0.7 billion. Where oil and gas guarantees associated with the Bureau of Ocean Energy Management do not include a stated cap, the amounts reflect management’s estimates of the potential exposure.

New Mexico Environmental and Reclamation Programs. FCX’s New Mexico operations are regulated under the New Mexico Water Quality Act and regulations adopted by the Water Quality Control Commission. In connection with discharge permits, the New Mexico Environment Department (NMED) has required each of these operations to submit closure plans for NMED’s approval. The closure plans must include measures to assure meeting applicable groundwater quality standards following the closure of discharging facilities and to abate groundwater or surface water contamination to meet applicable standards. FCX’s New Mexico operations also are subject to regulation under the 1993 New Mexico Mining Act (the Mining Act) and the related rules that are administered by the Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department. Under the Mining Act, mines are required to obtain approval of reclamation plans. The agencies approved updates to the closure plan and financial assurance instruments and completed a permit renewal for Chino in 2020 and Tyrone in 2021. At December 31, 2024, FCX had accrued reclamation and closure costs of $553 million for its New Mexico operations. Additional accruals may be required based on the state’s periodic review of FCX’s updated closure plans and any resulting permit conditions, and the amount of those accruals could be material.

Arizona Environmental and Reclamation Programs. FCX’s Arizona operations are subject to regulatory oversight by the ADEQ. ADEQ has adopted regulations for its aquifer protection permit (APP) program that require permits for, among other things, certain facilities, activities and structures used for mining, leaching, concentrating and smelting, and require compliance with aquifer water quality standards during operations and closure. An application for an APP requires a proposed closure strategy that will meet applicable groundwater protection requirements following cessation of operations and an estimate of the implementation cost, with a more detailed closure plan required at the time operations cease. A permit applicant must demonstrate its financial ability to meet the closure costs approved by ADEQ. Closure costs for facilities covered by APPs are required to be updated every six years and financial assurance mechanisms are required to be updated every two years. During 2022, the Morenci and Bagdad mines increased their AROs by $118 million and $65 million, respectively, associated with their updated closure strategies and plans for stockpiles and tailings impoundments that were submitted to ADEQ for approval. In accordance with FCX’s commitment to the Global Industry Standard on Tailings Management (the Tailings Standard), in 2024 Sierrita revised its closure plan and cost estimates resulting in a $157 million increase in its AROs. FCX will continue evaluating and, as necessary, updating its closure plans and closure cost estimates at other Arizona sites, and any such updates may also result in increased costs that could be significant.

Portions of Arizona mining facilities that operated after January 1, 1986, also are subject to the Arizona Mined Land Reclamation Act (AMLRA). AMLRA requires reclamation to achieve stability and safety consistent with post-mining land use objectives specified in a reclamation plan. Reclamation plans must be approved by the Arizona State Mine Inspector (ASMI) and must include an estimate of the cost to perform the reclamation measures specified in the plan along with financial assurance. In 2023, the ASMI requested updates to reclamation cost estimates and associated financial assurance for FCX’s Arizona mine sites, and in 2024, FCX submitted updated closure scopes of work and associated costs for Miami, Bagdad and Morenci. FCX will continue to evaluate options for future reclamation and closure activities at its operating and non-operating sites, which are likely to result in adjustments to FCX’s AROs, and those adjustments could be material.

At December 31, 2024, FCX had accrued reclamation and closure costs of $837 million for its Arizona operations and facilities.

Colorado Reclamation Programs. FCX’s Colorado operations are regulated by the Colorado Mined Land Reclamation Act (Reclamation Act) and regulations promulgated thereunder, which are consistent with the Tailings Standard. Under the Reclamation Act, mines are required to obtain approval of plans for reclamation of lands affected by mining operations to be performed during mining or upon cessation of mining operations. In 2024, both Henderson and Climax updated cost estimates associated with reclamation plans under the Reclamation Act and recorded a total increase of $162 million to their related AROs.

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In 2019, Colorado enacted legislation that requires proof of an end date for water treatment as a condition of permit authorizations for new mining operations and expansions beyond current permit authorizations. While this requirement does not apply to existing operations, it may lead to changes in long-term water management requirements at Climax and Henderson operations and their related AROs.

As of December 31, 2024, FCX had accrued reclamation and closure costs of $351 million for its Colorado operations.

Chile Reclamation and Closure Programs. El Abra is subject to regulation under the Mine Closure Law administered by the National Geology and Mining Service. In 2020, El Abra received approval of its updated closure plan and cost estimates, and in compliance with the requirement for five-year updates, El Abra expects to submit an updated plan with closure cost estimates in 2025. At December 31, 2024, FCX had accrued reclamation and closure costs of $105 million for its El Abra operation.

Peru Reclamation and Closure Programs. Cerro Verde is subject to regulation under the Mine Closure Law administered by the Peru Ministry of Energy and Mines (MINEM). Under the closure regulations, mines must submit a closure plan that includes the reclamation methods, closure cost estimates, methods of control and verification, closure and post-closure plans, and financial assurance. In compliance with the requirement for five-year updates, Cerro Verde submitted its updated closure plan and cost estimates and received approval from MINEM in December 2023. At December 31, 2024, FCX had accrued reclamation and closure costs of $230 million for its Cerro Verde operation.

Indonesia Reclamation and Closure Programs. The ultimate amount of reclamation and closure costs to be incurred at PT-FI’s operations will be determined based on applicable laws and regulations and PT-FI’s assessment of appropriate remedial activities under the circumstances, after consultation with governmental authorities, affected local residents and other affected parties and cannot currently be projected with precision. Some reclamation costs will be incurred during mining activities, while the remaining reclamation costs will be incurred after the end of mining activities, which are currently estimated to continue through 2041. In 2022, PT-FI recorded net increases to its ARO totaling $99 million related to higher estimated costs associated with West Wanagon slope stabilization remediation and increased reclamation activities and increased costs. In 2024, PT-FI recorded net increases to its ARO totaling $122 million primarily for revised reclamation plans for the Grasberg open pit area and adjustments resulting from a review and update of the PT-FI ARO model. At December 31, 2024, FCX had accrued reclamation and closure costs of $1.0 billion for its PT-FI operations.

Indonesia government regulations issued in 2010 require a company to provide a mine closure guarantee in the form of a time deposit placed in a state-owned bank in Indonesia. At December 31, 2024, PT-FI had restricted time deposits totaling $100 million for mine closure included in other assets.

Oil and Gas Properties. Substantially all of Freeport McMoRan Oil & Gas LLC’s (FM O&G’s), FCX’s subsidiary that holds its remaining oil and gas operations, oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove equipment and facilities from leased acreage, and restore land in accordance with applicable local, state and federal laws. Following several sales transactions, FM O&G’s remaining operating areas primarily include offshore California and the Gulf of Mexico (GOM, also referred to as Gulf of America). FM O&G recorded increases to its ARO totaling $163 million in 2024 and $91 million in 2023. As of December 31, 2024, FM O&G AROs cover approximately 180 wells and 150 platforms and other structures and it had accrued reclamation and closure costs of $538 million.

FM O&G’s ARO adjustments for 2024 include $116 million associated with assumed oil and gas abandonment obligations resulting from bankruptcies of other companies and were charged to production and delivery costs. FM O&G, as a predecessor-in-interest in oil and natural gas leases, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by its subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and have not performed the required abandonment obligations. Accordingly, regulations or federal laws require that other working interest owners, including FM O&G, assume such obligations.

Litigation. In addition to the pending legal proceedings discussed below and above under “Environmental,” we are involved periodically in ordinary routine litigation incidental to our business, some of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. SEC regulations require us to disclose
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environmental proceedings involving a governmental authority if we reasonably believe that such proceedings may result in monetary sanctions above a stated threshold. Pursuant to the SEC regulations, we use a threshold of $1 million for purposes of determining whether disclosure of any such environmental proceedings is required. Management does not believe, based on currently available information, that the outcome of any current pending legal proceeding will have a material adverse effect on FCX’s financial condition, although individual or cumulative outcomes could be material to FCX’s operating results for a particular period, depending on the nature and magnitude of the outcome and the operating results for the period.

Asbestos and Talc Claims. Since approximately 1990, various FCX affiliates have been named as defendants in a large number of lawsuits alleging personal injury from exposure to asbestos or talc allegedly contained in industrial products such as electrical wire and cable, raw materials such as paint and joint compounds, talc-based lubricants used in rubber manufacturing or from asbestos contained in buildings and facilities located at properties owned or operated by affiliates of FCX. Many of these suits involve a large number of codefendants. Based on litigation results to date and facts currently known, FCX believes that the amounts of any such losses, individually or in the aggregate, are not material to its consolidated financial statements. There can be no assurance that future developments will not alter this conclusion.

There has been a significant increase in the number of cases alleging the presence of asbestos contamination in talc-based cosmetic and personal care products and in cases alleging exposure to talc products that are not alleged to be contaminated with asbestos. The primary targets have been the producers of those products, but defendants in many of these cases also include talc miners. Cyprus Amax Minerals Company (CAMC), an indirect wholly owned subsidiary of FCX, and Cyprus Mines Corporation (Cyprus Mines), a wholly owned subsidiary of CAMC, are among those targets. Cyprus Mines was engaged in talc mining and processing from 1964 until 1992 when it exited its talc business by conveying it to a third party in two related transactions. Those transactions involved (1) a transfer by Cyprus Mines of the assets of its talc business to a newly formed subsidiary that assumed all pre-sale and post-sale talc liabilities, subject to limited reservations, and (2) a sale of the stock of that subsidiary to the third party. In 2011, the third party sold that subsidiary to Imerys Talc America (Imerys), an affiliate of Imerys S.A.

In accordance with the terms of the 1992 transactions and subsequent agreements, Cyprus Mines has contractual indemnification rights, subject to limited reservations, against Imerys, which historically acknowledged those indemnification obligations and took responsibility for all talc lawsuits against Cyprus Mines and CAMC tendered to it. However, in February 2019, Imerys filed for Chapter 11 bankruptcy protection, which triggered an immediate automatic stay under the federal bankruptcy code prohibiting any party from continuing or initiating litigation or asserting new claims against Imerys. As a result, Imerys stopped defending the talc lawsuits against Cyprus Mines and CAMC.

In January 2021, Imerys filed the form of a global settlement agreement to be entered into by CAMC, Cyprus Mines, FCX, Imerys and the other debtors, tort claimants’ committee and future claims representative in the Imerys bankruptcy. In accordance with the global settlement, among other things, (1) CAMC agreed to contribute a total of $130 million in cash to a settlement trust in seven annual installments, which will be guaranteed by FCX, and (2) CAMC and Cyprus Mines and their affiliates will contribute to the settlement trust all rights that they have to the proceeds of certain legacy insurance policies as well as indemnity rights they have against Johnson & Johnson. In accordance with the settlement, Cyprus Mines commenced its bankruptcy process in February 2021, with all talc lawsuits against CAMC, Cyprus Mines and FCX being stayed. The claimants failed to approve the Imerys bankruptcy plan in 2021, which resulted in a lengthy mediation process among the interested parties.
Mediation resulted in CAMC agreeing to contribute an additional $65 million over seven years to the claimant trust for a total contribution of $195 million. The claimants in both the Imerys and Cyprus Mines bankruptcy cases approved the global settlement in January 2025, which now remains subject to bankruptcy court approvals in both cases. There can be no assurance that the global settlement will be approved and successfully implemented.

At December 31, 2024, FCX had a litigation reserve of $195 million associated with the proposed settlement.

Tax Matters. FCX’s operations are in multiple jurisdictions where uncertainties arise in the application of complex tax regulations. Some of these tax regimes are defined by contractual agreements with the local government, while others are defined by general tax laws and regulations. FCX and its subsidiaries are subject to reviews of its income tax filings and other tax payments, and disputes can arise with the taxing authorities over the interpretation of its contracts or laws. The final taxes paid may be dependent upon many factors, including negotiations with taxing authorities. In certain jurisdictions, FCX pays a portion of the disputed amount before formally appealing an assessment. Such payment is recorded as a receivable if FCX believes the amount is collectible.
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Peru Tax Matters. Cerro Verde has received assessments from the National Superintendency of Customs and Administration (SUNAT) for additional taxes, penalties and interest related to various audit exceptions for income and other taxes. Cerro Verde has filed or will file objections to the assessments because it believes it has properly determined and paid its taxes. A summary of these assessments follows:
Tax YearTax Assessment
Penalties and Interest
Total
2003 to 2008$32 $112 $144 
20099 30 39 
20108 69 77 
2011 and 20125 36 41 
20138 26 34 
2014 to 202288 40 128 
$150 $313 $463 

As of December 31, 2024, Cerro Verde had paid $454 million of disputed tax assessments. A reserve has been applied against these payments totaling $179 million, resulting in a net receivable of $275 million (included in other assets), which Cerro Verde believes is collectible.

Cerro Verde’s income tax assessments, penalties and interest included in the table above totaled $397 million at December 31, 2024, of which $245 million has not been charged to expense.

Indonesia Tax Matters. PT-FI has received assessments from the Indonesia tax authorities for additional taxes and interest related to various audit exceptions for income and other taxes. PT-FI has filed objections to the assessments because it believes it has properly determined and paid its taxes. A summary of these assessments follows:
Tax YearTax AssessmentPenalties and InterestTotal
2005$61 $29 $90 
200745 21 66 
2013 and 20177 4 11 
$113 $54 $167 

As of December 31, 2024, PT-FI has paid $10 million on these disputed tax assessments (included in Other Assets), which PT-FI believes is collectible. The disputed tax assessments above include pending cases at the Indonesia Supreme Court related to withholding taxes for employees and other service providers for the years 2005 and 2007, which total $41 million (included in accounts payable and accrued liabilities) as of December 31, 2024.

PT-FI’s income tax assessments, penalties and interest included in the table above totaled $121 million at December 31, 2024, of which $117 million has not been charged to expense.

Indonesia Regulatory Matters.
Export Licenses. Current regulations in Indonesia prohibit exports of copper concentrate as of January 1, 2025. Pursuant to the terms of its special mining business license (IUPK) regarding force majeure events, PT-FI has requested approval from the Indonesia government to permit the export of copper concentrate in 2025 until the required repairs to its new smelter following the October 2024 fire incident and full ramp-up are complete.

Long-term Mining Rights. Pursuant to regulations issued during 2024, PT-FI is eligible to apply for an extension of its mining rights beyond 2041, provided certain conditions are met, including ownership of integrated downstream facilities that have entered the operational stage; domestic ownership of at least 51% and agreement with a state-owned enterprise for an additional 10% ownership; and commitments for additional exploration and increases in refining capacity, each as approved by the Ministry of Energy and Mineral Resources (MEMR). Application for extension may be submitted at any time up to one year prior to the expiration of PT-FI’s IUPK.

Administrative Fines. In June 2021, the MEMR, issued a ministerial decree for the calculation of an administrative fine for lack of smelter development in light of the COVID-19 pandemic, and in 2021, PT-FI recorded charges totaling $16 million for a potential settlement of the administrative fine. In January 2022, the Indonesia government submitted a new estimate of the administrative fine totaling $57 million, and in March 2022, PT-FI paid the administrative fine and recorded an additional charge of $41 million.

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In May 2023, the MEMR issued a new decree prescribing a revised formula for administrative fines for delays in construction of smelting and refining facilities, taking into account allowances for certain delays associated with the COVID-19 pandemic as verified by a third-party. In mid-July 2023, PT-FI submitted its third-party verified calculation, which resulted in an accrual for a potential administrative fine of $55 million based on the formula prescribed by the decree related to the period from August 2020 through January 2022. In December 2024, the Indonesia government assessed PT-FI a $59 million administrative fine for delays in development of the new downstream processing facilities related to the period from August 2020 through January 2022. As a result, PT-FI increased its accrual by $4 million at December 31, 2024.

Smelter Assurance. The May 2023 decree issued by MEMR also required assurance in the form of an escrow account, which can be withdrawn if smelter development progress is at least 90% on June 10, 2024. During 2023, PT-FI deposited $10 million in a joint account with the Indonesia government while it continued to discuss the applicability of the May 2023 decree. At December 31, 2024, development of PT-FI’s new downstream processing facilities was complete; as such, PT-FI does not believe additional deposits are necessary. Refer to Note 12 for discussion of PT-FI’s assurance bonds to support its commitment for smelter development in Indonesia.

Export Proceeds. In accordance with a regulation issued by the Indonesia government in 2023, 30% of PT-FI’s gross export proceeds are being temporarily deposited into Indonesia banks for a period of 90 days before withdrawal. At December 31, 2024, FCX had $0.7 billion in current restricted cash and cash equivalents deposited in Indonesia banks in accordance with this regulation.

The Indonesia government is considering changes to this regulation, which could increase the amount and length of the requirement, but also allow withdrawals from the balances to fund business requirements. The details of the modifications have not been finalized.

Letters of Credit, Bank Guarantees and Surety Bonds.  Letters of credit and bank guarantees totaled $638 million at December 31, 2024, primarily associated with reclamation and AROs, and copper concentrate shipments from PT-FI to Atlantic Copper as required by Indonesia regulations. In addition, FCX had surety bonds totaling $504 million at December 31, 2024, primarily associated with environmental obligations and AROs.

Insurance.  FCX purchases a variety of insurance products to mitigate potential losses, which typically have specified deductible amounts or self-insured retentions and policy limits. FCX generally is self-insured for U.S. workers’ compensation but purchases excess insurance up to statutory limits. An actuarial analysis is performed twice a year on the various casualty insurance programs covering FCX’s U.S.-based mining operations, including workers’ compensation, to estimate expected losses. At December 31, 2024, FCX’s liability for expected losses under these insurance programs totaled $54 million, which consisted of a current portion of $14 million (included in accounts payable and accrued liabilities) and a long-term portion of $40 million (included in other liabilities). In addition, FCX has receivables of $18 million (a current portion of $9 million included in other accounts receivable and a long-term portion of $9 million included in other assets) for expected claims associated with these losses to be filed with insurance carriers.

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NOTE 11.  COMMITMENTS AND GUARANTEES
Leases. The components of FCX’s leases presented in the consolidated balance sheets as of December 31 follow:
20242023
Lease right-of-use assets (included in property, plant, equipment and mine development costs, net)$853 $448 
Short-term lease liabilities (included in accounts payable and accrued liabilities)
$98 $84 
Long-term lease liabilities (included in other liabilities)
692 347 

Total lease liabilitiesa
$790 $431 
a.Includes finance leases associated with PT-FI’s new downstream processing facilities, including for an oxygen plant ($217 million at December 31, 2024), shallow draft vessels ($119 million at December 31, 2024), land ($95 million at December 31, 2024, and $130 million at December 31, 2023) and wharf ($90 million at December 31, 2024, and $93 million at December 31, 2023).

Operating lease costs, primarily included in production and delivery expense in the consolidated statements of income, for the years ended December 31 follow:
202420232022
Operating leases$44 $48 $46 
Variable and short-term leases146 
a
126 
a
84 
Total operating lease costs
$190 $174 $130 
a.Includes $50 million in 2024 and $30 million in 2023 related to a variable lease component of PT-FI’s tolling arrangement with PT Smelting. Refer to Note 2 for additional discussion of PT-FI’s commercial arrangement with PT Smelting.

Total finance lease costs, including both depreciation and interest, were $24 million in 2024 and $6 million in 2023 and 2022.

FCX acquired right-of-use assets through lease arrangements of $482 million in 2024, $167 million in 2023 and $76 million in 2022. FCX payments included in operating cash flows for its lease liabilities totaled $61 million in 2024 and 2023 and $41 million in 2022. FCX payments included in financing cash flows for its lease liabilities totaled $41 million in 2024, $3 million in 2023 and $7 million in 2022. As of December 31, 2024, the weighted-average discount rate used to determine the lease liabilities was 4.9% (4.7% as of December 31, 2023) and the weighted-average remaining lease term was 15.0 years (13.1 years as of December 31, 2023).

The future minimum payments for leases presented in the consolidated balance sheet at December 31, 2024, follow:
2025$131 
202696 
202781 
202867 
2029113 
Thereafter612 
Total payments1,100 
Less amount representing interest(310)
Present value of net minimum lease payments790 
Less current portion(98)
Long-term portion$692 

Contractual Obligations.  At December 31, 2024, based on applicable prices on that date, FCX has unconditional purchase obligations (including take-or-pay contracts with terms less than one year) of $3.7 billion, primarily comprising the procurement of copper concentrate ($3.1 billion), electricity ($0.2 billion) and transportation services ($0.2 billion). Some of FCX’s unconditional purchase obligations are settled based on the prevailing market rate for the service or commodity purchased. In some cases, the amount of the actual obligation may change over time because of market conditions. Obligations for copper concentrate provide for deliveries of specified volumes to Atlantic Copper at market-based prices. Transportation obligations are primarily associated with contracted ocean freight agreements for our South America and Indonesia operations. Electricity obligations are primarily for long-term power purchase agreements in North America and contractual minimum demand at the South America mines.
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FCX’s unconditional purchase obligations total $1.8 billion in 2025, $1.1 billion in 2026, $0.4 billion in 2027, $0.2 billion in 2028, $0.1 billion in 2029 and $0.1 billion thereafter. During the three-year period ended December 31, 2024, FCX fulfilled its minimum contractual purchase obligations.

IUPK – Indonesia. In December 2018, FCX completed the 2018 Transaction with the Indonesia government regarding PT-FI’s long-term mining rights and share ownership. Concurrent with the closing of the 2018 Transaction, the Indonesia government granted PT-FI an IUPK to replace its former contract of work. Under the terms of the IUPK, PT-FI was granted an extension of mining rights through 2031, with rights to extend mining rights through 2041, subject to PT-FI completing the development of additional smelting and refining capacity in Indonesia and fulfilling its defined fiscal obligations to the Indonesia government. The IUPK, and related documentation, contains legal and fiscal terms and is legally enforceable through 2041, assuming the additional extension is received. In addition, FCX, as a foreign investor, has rights to resolve investment disputes with the Indonesia government through international arbitration.

The key fiscal terms set forth in the IUPK include a 25% corporate income tax rate, a 10% profits tax on net income, and royalty rates of 4% for copper, 3.75% for gold and 3.25% for silver. PT-FI’s royalties charged against revenues totaled $433 million in 2024, $338 million in 2023 and $357 million in 2022.

Dividend distributions from PT-FI to FCX totaled $1.5 billion in 2024, $0.4 billion in 2023 and $2.5 billion in 2022, and are subject to a 10% withholding tax.

Export Duties. The IUPK required PT-FI to pay export duties of 5%, declining to 2.5% when smelter development progress exceeded 30% and eliminated when development progress for additional smelting and refining capacity in Indonesia exceeded 50%. In December 2022, PT-FI received approval, based on construction progress achieved, for a reduction in export duties from 5% to 2.5%, which was effective immediately. In March 2023, the Indonesia government further verified that construction progress of the new smelter exceeded 50% and PT-FI’s export duties were eliminated effective March 29, 2023.

In July 2023, the Ministry of Finance issued a revised regulation on duties for various exported products, including copper concentrates. Under the revised regulation PT-FI was assessed export duties for copper concentrates at 7.5% in the second half of 2023 (totaling $307 million). For 2024, the revised regulation assessed export duties for copper concentrates at 10% for companies with smelter progress of 70% to 90% and at 7.5% for companies with smelter progress exceeding 90%. As of December 31, 2023, construction progress of PT-FI’s smelter projects exceeded 90%; however, PT-FI was subject to the 10% export duty during 2024 until it received a revised concentrate export license. In July 2024, PT-FI was granted copper concentrate and anode slimes export licenses, which were valid through December 2024, subjecting PT-FI to a 7.5% export duty. PT-FI’s export duties totaled $457 million in 2024, $324 million in 2023 and $307 million in 2022.

Indemnification. The PT-FI divestment agreement, discussed in Note 2, provides that FCX will indemnify MIND ID and PTI from any losses (reduced by receipts) arising from any tax disputes of PT-FI disclosed to MIND ID in a Jakarta, Indonesia, tax court letter limited to PTI’s respective percentage share at the time the loss is finally incurred. Any net obligations arising from any tax settlement would be paid on December 21, 2025. FCX had accrued $49 million as of December 31, 2024, (included in accounts payable in the consolidated balance sheets) and $75 million as of December 31, 2023, (included in other long-term liabilities in the consolidated balance sheets) related to this indemnification.

Cobalt Business. In September 2021, FCX’s 56%-owned subsidiary, Koboltti Chemicals Holdings Limited (KCHL), completed the sale of its remaining cobalt business based in Kokkola, Finland (Freeport Cobalt) to Jervois Global Limited (Jervois) for $208 million (before post-closing adjustments), consisting of cash consideration of $173 million and 7% of Jervois common stock (valued at $35 million at the time of closing). In 2022, KCHL sold these shares for $60 million. In addition, KCHL has the right to receive contingent consideration through 2026 of up to $40 million based on the future performance of Freeport Cobalt. Any gain related to the contingent consideration will be recognized when received. Following this transaction, FCX no longer has cobalt operations.

Community Development Programs.  FCX has adopted policies that govern its working and engagement relationships with the communities where it operates. These policies are designed to guide FCX’s practices and programs in a manner that respects and promotes basic human rights and the culture of the local people impacted by FCX’s operations. FCX continues to make significant expenditures on community development, education, health, training and cultural programs.
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PT-FI provides funding and technical assistance to support various community development and empowerment programs in areas such as health, education, economic development and local infrastructure. In 1996, PT-FI established a social investment fund with the aim of contributing to social and economic development in the Mimika Regency. In 2019, a new foundation, the Amungme and Kamoro Community Empowerment Foundation (Yayasan Pemberdayaan Masyarakat Amungme dan Kamoro, or YPMAK) was established, and in 2020, PT-FI appointed YPMAK to assist in distributing a significant portion of PT-FI’s funding to support the development and empowerment of the local Indigenous Papuan people. YPMAK is governed by a Board of Governors consisting of seven representatives of Indigenous Kamoro-Amungme, PT-FI and Mind ID.

In addition, since 2001, PT-FI has voluntarily established and contributed to land rights trust funds administered by Amungme and Kamoro representatives that focus on socioeconomic initiatives, human rights and environmental issues.

PT-FI is committed to the continued funding of YPMAK programs and the land rights trust funds, as well as for other local-community development initiatives through the end of PT-FI's IUPK in support of public health, education, local economic development and empowerment. PT-FI recorded charges to production and delivery costs totaling $141 million in 2024 and $123 million in both 2023 and 2022 for social and economic development programs.

Guarantees.  FCX provides certain financial guarantees (including indirect guarantees of the indebtedness of others) and indemnities.

Prior to its acquisition by FCX, FMC and its subsidiaries have, as part of merger, acquisition, divestiture and other transactions, from time to time, indemnified certain sellers, buyers or other parties related to the transaction from and against certain liabilities associated with conditions in existence (or claims associated with actions taken) prior to the closing date of the transaction. As part of these transactions, FMC indemnified the counterparty from and against certain excluded or retained liabilities existing at the time of sale that would otherwise have been transferred to the party at closing. These indemnity provisions generally now require FCX to indemnify the party against certain liabilities that may arise in the future from the pre-closing activities of FMC for assets sold or purchased. The indemnity classifications include environmental, tax and certain operating liabilities, claims or litigation existing at closing and various excluded liabilities or obligations. Most of these indemnity obligations arise from transactions that closed many years ago, and given the nature of these indemnity obligations, it is not possible to estimate the maximum potential exposure. Except as described in the following sentence, FCX does not consider any of such obligations as having a probable likelihood of payment that is reasonably estimable, and accordingly, has not recorded any obligations associated with these indemnities. With respect to FCX’s environmental indemnity obligations, any expected costs from these guarantees are accrued when potential environmental obligations are considered by management to be probable and the costs can be reasonably estimated.

NOTE 12.  FINANCIAL INSTRUMENTS
FCX does not purchase, hold or sell derivative financial instruments unless there is an existing asset or obligation, or it anticipates a future activity that is likely to occur and will result in exposure to market risks, which FCX intends to offset or mitigate. FCX does not enter into any derivative financial instruments for speculative purposes, but has entered into derivative financial instruments in limited instances to achieve specific objectives. These objectives principally relate to managing risks associated with commodity price changes, foreign currency exchange rates and interest rates.

Commodity Contracts.  From time to time, FCX has entered into derivative contracts to hedge the market risk associated with fluctuations in the prices of commodities it purchases and sells. Derivative financial instruments used by FCX to manage its risks do not contain credit risk-related contingent provisions.
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A discussion of FCX’s derivative contracts and programs follows.

Derivatives Designated as Hedging Instruments – Fair Value Hedges
Copper Futures and Swap Contracts. Some of FCX’s U.S. copper rod and cathode customers request a fixed market price instead of the COMEX average copper price in the month of shipment. FCX hedges this price exposure in a manner that allows it to receive the COMEX average price in the month of shipment while the customers pay the fixed price they requested. FCX accomplishes this by entering into copper futures or swap contracts. Hedging gains or losses from these copper futures and swap contracts are recorded in revenues. FCX did not have any significant gains or losses resulting from hedge ineffectiveness during the three years ended December 31, 2024. At December 31, 2024, FCX held copper futures and swap contracts that qualified for hedge accounting for 109 million pounds at an average contract price of $4.31 per pound, with maturities through November 2026.

Summary of (Losses) Gains. A summary of realized and unrealized (losses) gains recognized in revenues for derivative financial instruments related to commodity contracts that are designated and qualify as fair value hedge transactions, including on the related hedged item for the years ended December 31 follows:
 202420232022
Copper futures and swap contracts:
Unrealized (losses) gains:
Derivative financial instruments$(32)$3 $(11)
Hedged item – firm sales commitments
32 (3)11 
Realized gains (losses):
Matured derivative financial instruments
29 (4)(63)
Derivatives Not Designated as Hedging Instruments
Embedded Derivatives. Certain FCX sales contracts provide for provisional pricing primarily based on the LME copper price or the COMEX copper price and the London gold price at the time of shipment as specified in the contract. FCX receives market prices based on prices in the specified future month, which results in price fluctuations recorded in revenues until the date of settlement.

FCX records revenues and invoices customers at the time of shipment based on then-current LME or COMEX copper prices and the London gold price as specified in the contracts, which results in an embedded derivative (i.e., a pricing mechanism that is finalized after the time of delivery) that is required to be bifurcated from the host contract. The host contract is the sale of the metals contained in the concentrate, cathode or anode slimes at the then-current LME copper, COMEX copper or London gold prices. FCX applies the normal purchases and normal sales scope exception in accordance with derivatives and hedge accounting guidance to the host contract in its concentrate, cathode and anode slime sales agreements since these contracts do not allow for net settlement and always result in physical delivery. The embedded derivative does not qualify for hedge accounting and is adjusted to fair value through earnings each period, using the period-end LME or COMEX copper forward prices and the adjusted London gold price, until the date of final pricing. Similarly, FCX purchases copper under contracts that provide for provisional pricing. Mark-to-market price fluctuations from these embedded derivatives are recorded through the settlement date and are reflected in revenues for sales contracts and in inventory for purchase contracts.


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A summary of FCX’s embedded derivatives at December 31, 2024, follows:
OpenAverage Price
Per Unit		Maturities
 PositionsContractMarketThrough
Embedded derivatives in provisional sales contracts:    
Copper (millions of pounds)282 $4.16 $3.96 May 2025
Gold (thousands of ounces)125 2,646 2,625 February 2025
Embedded derivatives in provisional purchase contracts:    
Copper (millions of pounds)74 4.09 3.96 March 2025

Copper Forward Contracts. Atlantic Copper enters into copper forward contracts designed to hedge its copper price risk whenever its physical purchases and sales pricing periods do not match. These economic hedge transactions are intended to hedge against changes in copper prices, with the mark-to-market hedging gains or losses recorded in production and delivery costs. At December 31, 2024, Atlantic Copper held net copper forward sales contracts for 85 million pounds at an average contract price of $4.06 per pound, with maturities through February 2025.

Summary of Gains (Losses). A summary of the realized and unrealized gains (losses) recognized in operating income for commodity contracts that do not qualify as hedge transactions, including embedded derivatives, for the years ended December 31 follows:
 202420232022
Embedded derivatives in provisional sales contractsa:
 Copper$117 $97 $(479)
 Gold and other metals169 55 (12)
Copper forward contractsb
1 (6)37 
a.Amounts recorded in revenues.
b.Amounts recorded in cost of sales as production and delivery costs.

Unsettled Derivative Financial Instruments
A summary of the fair values of unsettled commodity derivative financial instruments follows:
 December 31,
 20242023
Commodity Derivative Assets:
Derivatives designated as hedging instruments:  
Copper futures and swap contracts$— $4 
Derivatives not designated as hedging instruments:  
Embedded derivatives in provisional sales/purchase contracts10 76 
Copper forward contracts10 — 
Total derivative assets$20 $80 
Commodity Derivative Liabilities:  
Derivatives designated as hedging instruments:  
Copper futures and swap contracts$28 $— 
Derivatives not designated as hedging instruments:
Embedded derivatives in provisional sales/purchase contracts60 23 
Copper forward contracts1 1 
Total derivative liabilities$89 $24 
FCX’s commodity contracts have netting arrangements with counterparties with which the right of offset exists, and it is FCX’s policy to generally offset balances by contract on its balance sheet. FCX’s embedded derivatives on provisional sales/purchase contracts are netted with the corresponding outstanding receivable/payable balances.


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A summary of these net unsettled commodity contracts in the balance sheet follows (there were no offsetting amounts at December 31, 2024 and 2023):
Assets at December 31,Liabilities at December 31,
2024202320242023
Amounts presented in balance sheet:
Commodity contracts:
Embedded derivatives in provisional
sales/purchase contracts$10 $76 $60 $23 
Copper derivatives10 4 29 1 
$20 $80 $89 $24 
Balance sheet classification:
Trade accounts receivable$— $76 $53 $2 
Other current assets10 4 — — 
Accounts payable and accrued liabilities10 — 35 22 
Other liabilities— — 1 — 
$20 $80 $89 $24 

Credit Risk. FCX is exposed to credit loss when financial institutions with which it has entered into derivative transactions (commodity, foreign exchange and interest rate swaps) are unable to pay. To minimize the risk of such losses, FCX uses counterparties that meet certain credit requirements and periodically reviews the creditworthiness of these counterparties. As of December 31, 2024, the maximum amount of credit exposure associated with derivative transactions was $20 million.

Other Financial Instruments. Other financial instruments include cash, cash equivalents, restricted cash and cash equivalents, accounts receivable, investment securities, legally restricted trust assets, accounts payable and accrued liabilities, accrued income taxes, dividends payable and debt. The carrying value for these financial instruments classified as current assets or liabilities approximates fair value because of their short-term nature and generally negligible credit losses (refer to Note 13 for the fair values of investment securities, legally restricted funds and debt).

Cash, Cash Equivalents and Restricted Cash and Cash Equivalents. The following table provides a reconciliation of total cash, cash equivalents and restricted cash and cash equivalents presented in the consolidated statements of cash flows:
December 31,
20242023
Balance sheet components:
Cash and cash equivalentsa
$3,923 $4,758 
Restricted cash and cash equivalents, currentb
888 1,208 
Restricted cash and cash equivalents, long-term – included in other assets
100 97 
Total cash, cash equivalents and restricted cash and cash equivalents presented in the consolidated statements of cash flows$4,911 $6,063 
a.Includes (i) time deposits of $0.1 billion at December 31, 2024, and $0.3 billion at December 31, 2023, and (ii) cash designated for PT-FI’s new downstream processing facilities totaling $0.2 billion at December 31, 2023.
b.Includes (i) $0.7 billion at December 31, 2024, and $1.1 billion at December 31, 2023, associated with 30% of PT-FI’s export proceeds required to be temporarily deposited in Indonesia banks for 90 days in accordance with a regulation issued by the Indonesia government and (ii) $0.1 billion at December 31, 2024 and 2023, in assurance bonds to support PT-FI’s commitment for its new downstream processing facilities.
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NOTE 13.  FAIR VALUE MEASUREMENT
Fair value accounting guidance includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). FCX did not have any significant transfers in or out of Level 3 for 2024.

FCX’s financial instruments are recorded on the consolidated balance sheets at fair value except for contingent consideration associated with the sale of the Deepwater GOM oil and gas properties (which was recorded under the loss recovery approach) and debt. A summary of the carrying amount and fair value of FCX’s financial instruments (including those measured at NAV as a practical expedient), other than cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, accrued income taxes and dividends payable (refer to Note 12), follows:
 At December 31, 2024
CarryingFair Value
 AmountTotalNAVLevel 1Level 2Level 3
Assets    
Investment securities:a,b
    
U.S. core fixed income fund$27 $27 $27 $— $— $— 
Equity securities9 9 — 9 — — 
Total36 36 27 9 — — 
Legally restricted funds:a
    
U.S. core fixed income fund66 66 66 — — — 
Government mortgage-backed securities54 54 — — 54 — 
Government bonds and notes34 34 — — 34 — 
Corporate bonds31 31 — — 31 — 
Money market funds19 19 — 19 — — 
Asset-backed securities12 12 — — 12 — 
Collateralized mortgage-backed securities1 1 — — 1 — 
Total217 217 66 19 132 — 
Derivatives:c
Embedded derivatives in provisional sales/purchase contracts in a gross asset position10 10 — — 10 — 
Copper forward contracts10 10 — 4 6 — 
Total20 20 — 4 16 — 
Contingent consideration for the sale of the Deepwater GOM oil and gas propertiesa
3 3 — — — 3 
Liabilities    
Derivatives:c
    
Embedded derivatives in provisional sales/purchase contracts in a gross liability position60 60 — — 60 — 
Copper futures and swap contracts28 28 — 17 11 — 
Copper forward contracts1 1 — 1 — — 
Total89 89 — 18 71 — 
Long-term debt, including current portiond
8,948 8,807 — — 8,807 — 
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At December 31, 2023
 CarryingFair Value
 AmountTotalNAVLevel 1Level 2Level 3
Assets    
Investment securities:a,b
    
U.S. core fixed income fund$27 $27 $27 $— $— $— 
Equity securities6 6 — 6 — — 
Total 33 33 27 6 — — 
Legally restricted funds:a
    
U.S. core fixed income fund65 65 65 — — — 
Government mortgage-backed securities51 51 — — 51 — 
Government bonds and notes37 37 — — 37 — 
Corporate bonds29 29 — — 29 — 
Money market funds17 17 — 17 — — 
Asset-backed securities12 12 — — 12 — 
Collateralized mortgage-backed securities1 1 — — 1 — 
Total212 212 65 17 130 — 
Derivatives:c
    
Embedded derivatives in provisional sales/purchase contracts in a gross asset position76 76 — — 76 — 
Copper futures and swap contracts4 4 — 3 1 — 
Total80 80 — 3 77 — 
Contingent consideration for the sale of the Deepwater GOM oil and gas propertiesa
50 42 — — — 42 
Liabilities    
Derivatives:c
    
Embedded derivatives in provisional sales/purchase contracts in a gross liability position23 23 — — 23 — 
Copper forward contracts1 1 — 1 — — 
Total24 24 — 1 23 — 
Long-term debt, including current portiond
9,422 9,364 — — 9,364 — 
a.Current portion included in other current assets and long-term portion included in other assets.
b.Excludes amounts included in restricted cash and cash equivalents and other assets (which approximated fair value), primarily associated with (i) PT-FI’s export proceeds ($0.7 billion at December 31, 2024, and $1.1 billion at December 31, 2023), (ii) assurance bonds to support PT-FI’s commitment for new downstream processing facilities ($0.1 billion at December 31, 2024 and 2023) and (iii) PT-FI’s mine closure and reclamation guarantees ($0.1 billion at December 31, 2024 and 2023).
c.Refer to Note 12 for further discussion and balance sheet classifications.
d.Recorded at cost except for debt assumed in acquisitions, which are recorded at fair value at the respective acquisition dates.

Valuation Techniques. The U.S. core fixed income fund is valued at NAV. The fund strategy seeks total return consisting of income and capital appreciation primarily by investing in a broad range of investment-grade debt securities, including U.S. government obligations, corporate bonds, mortgage-backed securities, asset-backed securities and money market instruments. There are no restrictions on redemptions (which are usually within one business day of notice).

Equity securities are valued at the closing price reported on the active market on which the individual securities are traded and, as such, are classified within Level 1 of the fair value hierarchy.

Fixed income securities (government securities, corporate bonds, asset-backed securities and collateralized mortgage-backed securities) are valued using a bid-evaluation price or a mid-evaluation price. These evaluations are based on quoted prices, if available, or models that use observable inputs and, as such, are classified within Level 2 of the fair value hierarchy.


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Money market funds are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in active markets.

FCX’s embedded derivatives on provisional copper concentrate, copper cathode and gold purchases and sales are valued using quoted monthly LME or COMEX copper forward prices and the adjusted London gold prices at each reporting date based on the month of maturity (refer to Note 12 for further discussion); however, FCX’s contracts themselves are not traded on an exchange. As a result, these derivatives are classified within Level 2 of the fair value hierarchy.

FCX’s derivative financial instruments for copper futures and swap contracts and copper forward contracts that are traded on the respective exchanges are classified within Level 1 of the fair value hierarchy because they are valued using quoted monthly COMEX or LME prices at each reporting date based on the month of maturity (refer to Note 12 for further discussion). Certain of these contracts are traded on the over-the-counter market and are classified within Level 2 of the fair value hierarchy based on COMEX and LME forward prices.

In December 2016, FCX’s sale of its Deepwater GOM oil and gas properties included up to $150 million in contingent consideration (to be received over time) that was recorded at the total amount under the loss recovery approach. The fair value of this contingent consideration was calculated based on a discounted cash flow model using inputs that include third-party estimates for reserves, production rates and production timing, and discount rates. Because significant inputs are not observable in the market, the contingent consideration is classified within Level 3 of the fair value hierarchy. In third-quarter 2024, FCX determined that only $4 million of the remaining balance was collectible and recorded a net impairment of $32 million (consisting of a $42 million impairment to the contingent consideration receivable and an offsetting reduction of $10 million to the related overriding royalty interest payable).

Long-term debt, including current portion, is primarily valued using available market quotes and, as such, is classified within Level 2 of the fair value hierarchy.

The techniques described above may produce a fair value that may not be indicative of NRV or reflective of future fair values. Furthermore, while FCX believes its valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial instruments could result in a different fair value measurement at the reporting date. There have been no changes in the techniques used at December 31, 2024, as compared to those techniques used at December 31, 2023.

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NOTE 14.  BUSINESS SEGMENT INFORMATION
Product Revenues. FCX’s revenues attributable to the products it sold for the years ended December 31 follow:
 202420232022
Copper:
Cathode$8,316 $6,629 $5,134 
Concentrate6,726 7,127 9,650 
Rod and other refined copper products3,851 3,659 3,699 
Purchased coppera
693 416 481 
Gold4,446 3,472 3,397 
Molybdenum1,801 2,006 1,416 
Silver and other631 585 688 
Adjustments to revenues:
Royalty expenseb
(442)(346)(366)
Treatment charges(396)(538)(503)
PT-FI export dutiesc
(457)(307)(325)
Revenues from contracts with customers25,169 22,703 23,271 
Embedded derivativesd
286 152 (491)
Total consolidated revenues$25,455 $22,855 $22,780 
a.FCX purchases copper cathode primarily for processing by its Rod & Refining operations.
b.Reflects royalties on sales from PT-FI and Cerro Verde that will vary with the volume of metal sold and prices.
c.Refer to Note 11 for further discussion of PT-FI export duties. Amounts include credits (charges) of $17 million in 2023 and $(18) million in 2022 associated with adjustments to prior-period export duties.
d.Refer to Note 12 for discussion of embedded derivatives related to FCX’s provisionally priced concentrate and cathode sales contracts.

Geographic Area. Information concerning financial data by geographic area follows:
December 31,
 20242023
Long-lived assets:a
  
Indonesia$22,580 $20,602 
U.S.10,468 9,386 
Peru6,452 6,563 
Chile1,120 1,105 
Other496 355 
Total$41,116 $38,011 
a.Excludes deferred tax assets and intangible assets.
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Years Ended December 31,
 202420232022
Revenues:a
   
U.S.$7,806 $7,264 $7,339 
Japan5,930 3,431 2,462 
Switzerland4,251 3,971 2,740 
Singapore1,116 1,178 1,492 
Indonesia1,108 767 3,026 
Spain1,052 1,251 1,174 
China743 1,081 929 
Germany500 714 632 
Chile451 428 383 
France306 226 177 
Philippines283 396 249 
India273 354 330 
Egypt239 229 149 
South Korea203 267 302 
United Kingdom115 171 355 
Other1,079 1,127 1,041 
Total$25,455 $22,855 $22,780 
a.Revenues are attributed to countries based on the location of the customer.

Major Customers and Affiliated Companies. Sales to MMC, PT-FI’s joint venture partner in PT Smelting, were 17% of FCX’s consolidated revenues in 2024 and totaled $4.4 billion in 2024, $2.0 billion in 2023 and $0.6 billion in 2022. Sales to PT Smelting were 13% of FCX’s consolidated revenues in 2022 and totaled $3.0 billion in 2022. Sales to PT Smelting totaled $27 million in 2023 (reflecting adjustments to prior period provisionally priced concentrate sales). MMC and PT Smelting are the only customers that accounted for 10% or more of FCX’s annual consolidated revenues during the three years ended December 31, 2024.

Consolidated revenues include sales to the noncontrolling interest owners of FCX’s South America mining operations and Morenci’s joint venture partners totaling $1.6 billion in 2024, $1.4 billion in 2023 and $1.7 billion in 2022.

Labor Matters. As of December 31, 2024, approximately 28% of FCX’s global labor force was covered by collective labor agreements (CLAs), none of which will expire during 2025.

Business Segments. FCX has organized its mining operations into four primary divisions – North America copper mines, South America operations, Indonesia operations and Molybdenum mines, and operating segments that meet certain thresholds are reportable segments. Separately disclosed in the following tables are FCX’s reportable segments, which include the Morenci and Cerro Verde copper mines, the Indonesia operations (including the Grasberg minerals district and PT-FI’s new downstream processing facilities), the Rod & Refining operations and Atlantic Copper Smelting & Refining.

FCX's Chief Executive Officer is identified as its CODM under business segment reporting guidance. Operating income (loss) is the financial measure of profit or loss used by the CODM to review segment results, and the significant segment expenses reviewed by the CODM are consistent with the operating expense line items presented in FCX’s consolidated statements of income. The CODM uses operating income (loss) to assess segment performance against forecasted results and to allocate resources, including capital investment in mining operations and potential expansions.

The 2023 and 2022 tables have been adjusted to conform with the current year presentation, primarily for the combination of the Grasberg minerals district and PT-FI’s new downstream processing facilities. PT-FI’s new downstream processing facilities will exclusively receive concentrate from the Grasberg minerals district, which reflects PT-FI’s integrated and dependent operations within Indonesia (i.e., Indonesia operations). The PMR will receive anode slimes from the smelter and from PT Smelting. FCX's CODM makes executive management decisions, including resource allocation and mine planning, for the Indonesia operations as a single business segment.

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Intersegment sales between FCX’s business segments are based on terms similar to arm’s-length transactions with third parties at the time of the sale. Intersegment sales may not be reflective of the actual prices ultimately realized because of a variety of factors, including additional processing, the timing of sales to unaffiliated customers and transportation premiums.

FCX defers recognizing profits on intercompany sales to Atlantic Copper until final sales to third parties occur. Until December 31, 2022, FCX also deferred recognizing 39.5% of PT-FI’s sales to PT Smelting, until final sales to third parties occurred. Beginning in 2023, PT-FI’s commercial arrangement with PT Smelting changed to a tolling arrangement and there were no further sales from PT-FI to PT Smelting during 2023 and 2024. Quarterly variations in ore grades, the timing of intercompany shipments and changes in product prices result in variability in FCX’s net deferred profits and quarterly earnings.

FCX allocates certain operating costs, expenses and capital expenditures to its operating divisions and individual segments. However, not all costs and expenses applicable to an operation are allocated. U.S. federal and state income taxes are recorded and managed at the corporate level (included in Corporate, Other & Eliminations), whereas foreign income taxes are recorded and managed at the applicable country level. In addition, some selling, general and administrative costs are not allocated to the operating divisions or individual reportable segments. Accordingly, the following segment information reflects management determinations that may not be indicative of what the actual financial performance of each operating division or reportable segment would be if it was an independent entity.

North America Copper Mines. FCX operates seven open-pit copper mines in North America – Morenci, Safford (including Lone Star), Bagdad, Sierrita and Miami in Arizona, and Chino and Tyrone in New Mexico. The North America copper mines include open-pit mining, sulfide-ore concentrating, leaching and SX/EW operations. A majority of the copper produced at the North America copper mines is cast into copper rod by FCX’s Rod & Refining segment. In addition to copper, certain of FCX’s North America copper mines also produce molybdenum concentrate, gold and silver.

The Morenci open-pit mine, located in southeastern Arizona, produces copper cathode and copper concentrate. In addition to copper, the Morenci mine also produces molybdenum concentrate. During 2024, the Morenci mine produced 41% of FCX’s North America copper and 12% of FCX’s consolidated copper production.

South America Operations. South America operations includes two operating copper mines – Cerro Verde in Peru and El Abra in Chile. These operations include open-pit mining, sulfide-ore concentrating, leaching and SX/EW operations.

The Cerro Verde open-pit copper mine, located near Arequipa, Peru, produces copper cathode and copper concentrate. In addition to copper, the Cerro Verde mine also produces molybdenum concentrate and silver. During 2024, the Cerro Verde mine produced 81% of FCX’s South America copper and 23% of FCX’s consolidated copper production.

Indonesia Operations. Indonesia operations include PT-FI’s Grasberg minerals district that produces copper concentrate that contains significant quantities of gold and silver, and PT-FI’s new downstream processing facilities. During 2024, PT-FI’s Grasberg minerals district produced 43% of FCX’s consolidated copper production and 99% of FCX’s consolidated gold production.
 
Molybdenum Mines. Molybdenum mines include the wholly owned Henderson underground mine and Climax open-pit mine, both in Colorado. The Henderson and Climax mines produce high-purity, chemical-grade molybdenum concentrate, which is typically further processed into value-added molybdenum chemical products.

Rod & Refining. The Rod & Refining segment consists of copper conversion facilities located in North America, and includes a refinery and two rod mills, which are combined in accordance with segment reporting aggregation guidance. These operations process copper produced at FCX’s North America copper mines and purchased copper into copper cathode and rod. At times these operations refine copper and produce copper rod for customers on a toll basis. Toll arrangements require the tolling customer to deliver appropriate copper-bearing material to FCX’s facilities for processing into a product that is returned to the customer, who pays FCX for processing its material into the specified products.

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Atlantic Copper Smelting & Refining. Atlantic Copper smelts and refines copper concentrate and markets refined copper and precious metals in slimes. During 2024, Atlantic Copper purchased 2% of its concentrate requirements from FCX’s North America copper mines, 15% from FCX’s South America operations and 13% from FCX’s Indonesia operations, with the remainder purchased from unaffiliated third parties.

Corporate, Other & Eliminations. Corporate, Other & Eliminations consists of FCX’s other mining, oil and gas operations and other corporate and elimination items, which include the Miami smelter, molybdenum conversion facilities in the U.S. and Europe, certain non-operating copper mines in North America (Ajo, Bisbee and Tohono in Arizona) and other mining support entities.
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Financial Information by Business Segment
North America Copper MinesSouth America Operations     
AtlanticCorporate,
CopperOther
CerroIndonesiaMolybdenumRod &Smelting& Elimi-FCX
MorenciOtherTotalVerdeOtherTotalOperationsMinesRefining& RefiningnationsTotal
Year Ended December 31, 2024          
Revenues:           
Unaffiliated customers$101 $79 $180 $3,618 $915 $4,533 $9,774 $— $6,196 $3,009 $1,763 
a
$25,455 
Intersegment2,246 3,814 6,060 638 — 

638 544 592 43 8 (7,885)— 
Production and delivery1,826 3,170 4,996 2,529 
b
701 3,230 3,368 
c
530 6,206 2,912 (5,688)
d
15,554 
e
Depreciation, depletion and amortization187 252 439 380 66 446 1,193 73 4 28 58 2,241 
Selling, general and administrative expenses2 2 4 8 — 8 127 — — 28 346 

513 
Exploration and research expenses17 27 44 12 4 16 8 — — — 88 156 
Environmental obligations and shutdown costs— — — — — — — — — — 127 127 
Operating income (loss)315 442 757 1,327 144 1,471 5,622 (11)29 49 

(1,053)6,864 
Interest expense, net— 1 1 21 — 21 28 — — 36 233 

319 
Other (expense) income, net(1)2 1 42 24 66 136 — (1)13 147 362 
Provision for (benefit from) income taxes— — — 542 

62 604 1,907 
f
— — (11)23 2,523 
Equity in affiliated companies’ net earnings — — — — — — 7 — — — 8 15 
Net income attributable to noncontrolling interests— — — 412 
g
67 479 2,022 
h
— — — 9 2,510 
Net income attributable to common stockholders1,889 
Total assets at December 31, 20243,228 6,766 9,994 8,096 2,060 10,156 27,309 2,018 202 1,705 3,464 54,848 
Capital expenditures184 849 1,033 293 82 375 2,908 117 35 142 198 4,808 
North America Copper MinesSouth America Operations     
AtlanticCorporate,
CopperOther
CerroIndonesiaMolybdenumRod &Smelting& Elimi-FCX
MorenciOtherTotalVerdeOtherTotalOperationsMinesRefining& RefiningnationsTotal
Year Ended December 31, 2023           
Revenues:            
Unaffiliated customers$91 $152 $243 $3,330 $824 $4,154 $7,816 
i
$— $5,886 $2,791 $1,965 
a
$22,855 
Intersegment2,328 3,745 6,073 787 — 787 621 677 40 19 (8,217)— 
Production and delivery1,730 3,048 4,778 2,529 710 3,239 2,570 
c
439 5,901 2,718 

(6,018)
d
13,627 
e
Depreciation, depletion and amortization175 243 418 395 64 459 1,028 66 5 28 64 2,068 
Selling, general and administrative expenses2 2 4 9 — 9 129 — — 28 309 479 
Exploration and research expenses11 39 50 10 4 14 2 — — — 71 137 
Environmental obligations and shutdown costs(1)28 27 — — — — — — — 292 
j
319 
Operating income (loss)502 537 1,039 1,174 46 1,220 4,708 172 20 36 (970)6,225 
Interest expense, net— 1 1 77 
k
— 77 35 — — 31 371 515 
Net gain on early extinguishment of debt— — — — — — — — — — 10 10 
Other (expense) income, net(5)3 (2)(13)
k
11 (2)122 (1)(2)(8)179 286 
Provision for (benefit from) income taxes— — — 495 17 512 1,774 — — — (16)2,270 
Equity in affiliated companies’ net earnings — — — — — — 10 — — — 5 15 
Net income (loss) attributable to noncontrolling interests— — — 300 
g
36 336 1,614 
h
— — — (47)1,903 
Net income attributable to common stockholders1,848 
Total assets at December 31, 20233,195 5,996 9,191 8,120 1,930 10,050 25,548 1,782 172 1,326 4,437 52,506 
Capital expenditures232 529 761 271 97 368 3,324 84 13 64 210 4,824 

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Financial Information by Business Segment (continued)
North America Copper MinesSouth America Operations     
AtlanticCorporate,
CopperOther
CerroIndonesiaMolybdenumRod &Smelting& Elimi-FCX
MorenciOtherTotalVerdeOtherTotalOperationsMinesRefining& RefiningnationsTotal
Year Ended December 31, 2022           
Revenues:            
Unaffiliated customers$175 $253 $428 $3,444 $768 $4,212 $8,028 
i
$— $6,281 $2,439 $1,392 
a
$22,780 
Intersegment2,514 3,768 6,282 506 — 

506 398 565 31 4 (7,786)— 
Production and delivery1,550 2,827 4,377 2,369 705 3,074 2,686 
c
359 6,330 2,452 
l
(6,208)
d
13,070 
e
Depreciation, depletion and amortization177 233 410 357 51 408 1,025 74 5 27 70 2,019 
Selling, general and administrative expenses2 3 5 8 — 8 117 — — 25 265 420 
Exploration and research expenses2 45 47 5 4 9 — 3 — — 56 115 
Environmental obligations and shutdown costs(5)1 (4)— — — — — — — 125 121 
Net gain on sales of assets— — — — — — — — — — (2)

(2)
Operating income (loss)963 912 1,875 1,211 8 1,219 4,598 129 (23)(61)(700)7,037 
Interest expense, net1 1 2 15 — 15 38 — — 15 490 560 
Net (loss) gain on early extinguishment of debt— — — — — — (11)— — — 42 31 
Other (expense) income, net(2)(30)(32)13 4 17 120 — (1)13 90 207 
Provision for (benefit from) income taxes— — — 461 (8)453 1,820 — — (1)(5)2,267 
Equity in affiliated companies’ net earnings — — — — — — 24 — — — 7 31 
Net income attributable to noncontrolling interests— — — 372 
g
35 407 592 
h
— — — 12 1,011 
Net income attributable to common stockholders3,468 
Total assets at December 31, 20223,052 5,552 8,604 8,398 1,873 10,271 22,727 1,697 183 1,262 6,349 

51,093 
Capital expenditures263 334 597 164 140 304 2,382 33 9 76 68 3,469 
a.Includes revenues from FCX’s molybdenum sales company, which includes sales of molybdenum produced by the Molybdenum mines and by certain of the North America and South America copper mines.
b.Includes nonrecurring labor-related charges totaling $97 million associated with Cerro Verde’s new CLAs with its two unions.
c.Includes charges for administrative fines of $4 million in 2024, $55 million in 2023 and $41 million in 2022. Also includes charges (credits) totaling $144 million in 2024, $(112) million in 2023 and $116 million in 2022 associated with ARO adjustments. Refer to Note 10 for further discussion.
d.Includes oil and gas charges totaling $217 million in 2024, $70 million in 2023 and $6 million in 2022 related to asset impairments and adjustments to AROs, including assumed abandonment obligations resulting from bankruptcies of other companies.
e.Includes metals inventory adjustments of $91 million in 2024, $14 million in 2023, and $29 million in 2022.
f.Includes a net benefit to income taxes totaling $182 million associated with the closure of PT-FI’s 2021 corporate income tax audit and resolution of the framework for Indonesia disputed tax matters. Refer to Note 9 for further discussion.
g.Beginning in September 2024, FCX’s interest in Cerro Verde is 55.08%, and prior to September 2024 was 53.56%.
h.Beginning January 1, 2023, FCX’s economic and ownership interest in PT-FI is 48.76% except for net income associated with the settlement of historical tax matters in 2024 and approximately 190 thousand ounces of gold sales in 2023, which were attributed based on the economic interests prior to January 1, 2023 (i.e., approximate 81% to FCX and 19% to MIND ID). Refer to Note 2 for further discussion.
i.Includes sales to PT Smelting totaling $27 million in 2023 (reflecting adjustments to prior period provisionally priced concentrate sales), and $3.0 billion in 2022.
j.Includes a charge of $65 million associated with an adjustment to the proposed settlement of talc-related litigation.
k.Interest expense, net includes $74 million of charges associated with contested tax rulings issued by the Peru Supreme Court, partly offset by a $13 million credit for the settlement of interest on Cerro Verde’s historical profit sharing liability. Other (expense) income, net includes a charge of $69 million associated with contested tax rulings issued by the Peru Supreme Court.
l.Includes maintenance charges and idle facility costs associated with a major maintenance turnaround at Atlantic Copper totaling $41 million.

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NOTE 15.  SUPPLEMENTARY MINERAL RESERVE INFORMATION (UNAUDITED)
Recoverable proven and probable mineral reserves as of December 31, 2024, have been prepared using industry accepted practice and conform to the disclosure requirements under Subpart 1300 of SEC Regulation S-K. FCX’s proven and probable mineral reserves may not be comparable to similar information regarding mineral reserves disclosed in accordance with the guidance in other countries. Proven and probable mineral reserves were determined by the use of mapping, drilling, sampling, assaying and evaluation methods generally applied in the mining industry. Mineral reserves, as used in the reserve data presented here, mean an estimate of tonnage and grade of measured and indicated mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. Proven mineral reserves are the economically mineable part of a measured mineral resource. To classify an estimate as a proven mineral reserve, the qualified person must possess a high degree of confidence of tonnage, grade and quality. Probable mineral reserves are the economically mineable part of an indicated or, in some cases, a measured mineral resource. The qualified person’s level of confidence will be lower in determining a probable mineral reserve than it would be in determining a proven mineral reserve. To classify an estimate as a probable mineral reserve, the qualified person’s confidence must still be sufficient to demonstrate that extraction is economically viable considering reasonable investment and market assumptions.

FCX’s mineral reserve estimates are based on the latest available geological and geotechnical studies. FCX conducts ongoing studies of its ore bodies to evaluate economic values and to manage risk. FCX revises its mine plans and estimates of proven and probable mineral reserves as required in accordance with the latest available studies.

Estimated recoverable proven and probable mineral reserves at December 31, 2024, were determined using metals price assumptions of $3.25 per pound for copper, $1,600 per ounce for gold and $12.00 per pound for molybdenum. For the three-year period ended December 31, 2024, LME copper settlement prices averaged $4.00 per pound, London PM gold prices averaged $2,044 per ounce and the weekly average price for molybdenum quoted by Platts Metals Daily averaged $21.41 per pound.

The recoverable proven and probable mineral reserves presented in the table below represent the estimated metal quantities from which FCX expects to be paid after application of estimated metallurgical recoveries and smelter recoveries, where applicable.
Estimated Recoverable Proven and Probable Mineral Reserves
at December 31, 2024
Coppera
(billion pounds)
Gold
(million ounces)
Molybdenum
(billion pounds)
North America41.6 0.6 2.51 
South America28.4 — 0.66 
Indonesiab
27.0 22.4 — 
Consolidated basisc
97.0 23.0 3.16 
Net equity interestb,d
70.2 11.5 2.87 
Note: Totals may not foot because of rounding.
a.Estimated consolidated recoverable copper reserves included 1.4 billion pounds in leach stockpiles and 0.3 billion pounds in mill stockpiles.
b.Estimated recoverable proven and probable mineral reserves from Indonesia reflect estimates of minerals that can be recovered through 2041. As a result, PT-FI’s current long-term mine plan and planned operations are based on the assumption that PT-FI will abide by the terms and conditions of the IUPK and will be granted the 10-year extension from 2031 through 2041 (refer to Note 11 for discussion of PT-FI’s IUPK). As a result, PT-FI will not mine all of these mineral reserves during the initial term of the IUPK. Prior to the end of 2031, PT-FI expects to mine 40% of its recoverable proven and probable mineral reserves at December 31, 2024, representing 45% of FCX’s net equity share of recoverable copper reserves and 44% of FCX’s net equity share of recoverable gold reserves in Indonesia.
c.Consolidated mineral reserves represent estimated metal quantities after reduction for joint venture partner interests at the Morenci mine in North America (refer to Note 2 for further discussion). Excluded from the table above were FCX’s estimated recoverable proven and probable mineral reserves of 318 million ounces of silver, which were determined using $20 per ounce.
d.Net equity interest mineral reserves represent estimated consolidated metal quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of FCX’s ownership in subsidiaries). Excluded from the table above were FCX’s estimated recoverable proven and probable mineral reserves of 213 million ounces of silver.
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Estimated Recoverable Proven and Probable Mineral Reserves
at December 31, 2024
Orea
(million metric tons)
Average Ore Grade
Per Metric Tona
Recoverable Proven and
Probable Mineral Reservesb
FCX’s
Interest		FCX’s
Interest		100%
Basis		Copper (%)Gold (grams)Molybdenum (%)Copper
(billion pounds)		Gold
(million ounces)		Molybdenum
(billion pounds)
North America        
Production stage:       
Morenci
72%
2,739 3,804 0.21— — 
c
11.1 — 0.17 
Sierrita
100%
2,206 2,206 0.23— 
c
0.03 9.4 0.1 0.96 
Bagdad
100%
2,430 2,430 0.35— 
c
0.02 15.8 0.2 0.86 
Safford, including
   Lone Star
100%
746 746 0.43— — 5.1 — — 
Chino, including Cobre
100%
370 370 0.450.04— 3.0 0.4 — 
Climax
100%
141 141 — —  0.15 — — 0.42 
Henderson
100%
44 44 — —  0.16 — — 0.14 
Tyrone
100%
69 69 0.19—  — 0.3 — — 
Miami
100%
— — — —  — 0.1 — — 
South America        
Production stage:       
Cerro Verde
55.08%
2,145 3,894 0.34—  0.01 25.2 — 0.66 
El Abra
51%
312 611 0.43—  — 3.1 — — 
Indonesiad
       
Production stage:     
Grasberg Block Cave
48.76%
351 719 0.990.66 — 13.4 10.3 — 
Deep Mill Level Zone
48.76%
159 326 0.740.60 — 4.4 4.9 — 
Big Gossan
48.76%
23 48 2.230.95 — 2.2 1.0 — 
Development stage:       
Kucing Liar
48.76%
180 369 1.100.94 — 7.1 6.2 — 
Total 100% basis15,779 100.1 23.0 3.21 
Consolidated basise
14,714     97.0 23.0 3.16 
FCX’s net equity interestf
11,916     70.2 11.5 2.87 
Note: Totals may not foot because of rounding.
a.Excludes material contained in stockpiles.
b.Includes estimated recoverable metals contained in stockpiles.
c.Amounts not shown because of rounding.
d.Estimated recoverable proven and probable mineral reserves from Indonesia reflect estimates of minerals that can be recovered through 2041. Refer to Note 11 for discussion of PT-FI’s IUPK.
e.Consolidated mineral reserves represent estimated metal quantities after reduction for Morenci’s joint venture partner interests (refer to Note 2 for further discussion).
f.Net equity interest mineral reserves represent estimated consolidated metal quantities further reduced for noncontrolling interest ownership (refer to Note 2 for further discussion of FCX’s ownership in subsidiaries).
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Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Not applicable.

Item 9A.  Controls and Procedures.

(a)           Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report on Form 10-K. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.

(b)           Changes in internal controls over financial reporting. There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2024, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

(c)           Management’s annual report on internal control over financial reporting and the report thereon of Ernst & Young LLP are included herein under Item 8. “Financial Statements and Supplementary Data.”

Item 9B.  Other Information.

Director and Officer Trading Arrangements
During the quarter ended December 31, 2024, no director or officer of FCX adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as such terms are defined in Item 408(a) of Regulation S-K.

Amended and Restated Executive Employment Agreement
As previously reported, Kathleen L. Quirk, the President of FCX, was promoted to the additional role of Chief Executive Officer (CEO) of FCX effective June 11, 2024. In light of her expanded responsibilities, on February 11, 2025, she and FCX entered into an Amended and Restated Executive Employment Agreement (the Agreement), which amends and restates the Amended and Restated Executive Employment Agreement between FCX and Ms. Quirk dated effective December 2, 2008, and amended effective April 27, 2011 (the Prior Agreement). The Agreement reflects Ms. Quirk’s roles with FCX and includes other updates to incorporate current market practices. The Agreement is effective through December 31, 2027, after which it will automatically renew for additional one-year periods unless prior written notice of non-renewal is provided to the other party in accordance with the terms of the Agreement.

The principal terms of the Agreement are substantially similar to the Prior Agreement and does not change Ms. Quirk’s current compensation, although her base salary has been updated to reflect her base salary as of the date she assumed the role of CEO. The Agreement revises certain potential severance benefits to better align with current market practices. Specifically, in connection with a termination without Cause or with Good Reason unrelated to a Change in Control (as such terms are defined in the Agreement), the severance payment multiple has been reduced from three times to two times. In connection with a termination without Cause or with Good Reason related to a Change in Control, the multiple remains at three times, but the protected period has been reduced from three years to two years and includes a limited pre-Change in Control period. In addition, the severance payment related to a Change in Control will be calculated using the three-year average bonus (instead of the highest bonus during that period), and the pro-rated bonus for the year of termination will likewise be based on the three-year average bonus (instead of actual results for the year). The benefit continuation period in connection with all qualifying terminations has been reduced from three years to two years.

The Agreement also requires Ms. Quirk to deliver a release in favor of FCX in order to receive certain severance benefits, extends Ms. Quirk’s limited covenant not to compete from six months to eighteen months post-termination, and specifically confirms the application of FCX’s Incentive-Based Compensation Recovery Policy on Ms. Quirk’s compensation, where applicable.

The foregoing description of the Agreement does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the Agreement, which is attached this Form 10-K as Exhibit 10.8 and incorporated by reference herein.
176

Item 9C.  Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance.

The information required by this item regarding our executive officers appears in a separately captioned heading after Item 4. “Information About Our Executive Officers” in Part I of this report.

We have a Principles of Business Conduct, which defines the expected behavior of our Board of Directors and all of our employees, including our principal executive officer, principal financial officer, principal accounting officer and controller, and persons performing similar functions. We have posted a copy of our Principles of Business Conduct on our website at fcx.com under “About Us – Corporate Governance – Governance Documents.” Amendments to, or waivers of, our Principles of Business Conduct granted to any of our directors or executive officers will be published promptly on our website at fcx.com.

The information required by this item is incorporated by reference to “Information About Director Nominees,” “Board Committees,” and “Board and Committee Independence; Audit Committee Financial Experts,” and “Compensation Processes and Policies” in our definitive proxy statement to be filed with the United States Securities and Exchange Commission (SEC), relating to our 2025 annual meeting of stockholders.

Item 11.  Executive Compensation.

The information required by this item is incorporated herein by reference to “Director Compensation” and “Executive Officer Compensation” in our definitive proxy statement to be filed with the SEC, relating to our 2025 annual meeting of stockholders.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Equity Compensation Plan Information
Only our stockholder-approved 2016 Stock Incentive Plan has shares of our common stock available for future grant. However, we have equity compensation plans pursuant to which awards have previously been made that could result in issuance of our common stock to employees and non-employees as compensation.
The following table presents information regarding our equity compensation plans as of December 31, 2024:
Number of Securities To be Issued Upon Exercise of Outstanding Options, Warrants and RightsWeighted-Average Exercise Price of Outstanding Options, Warrants and RightsNumber of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
(a)(b)(c)
Equity compensation plans approved by security holders
12,773,631 a$14.22 15,048,374 
Equity compensation plans not approved by security holders
13,500 b— 
   Total12,787,131 $14.22 15,048,374 

a.Includes shares of our common stock issuable upon the vesting of 3,325,514 restricted stock units (RSUs) and 2,619,000 performance share units at maximum performance levels, and the termination of deferrals with respect to 1,220,070 RSUs that were vested as of December 31, 2024. These awards are not reflected in column (b) because they do not have an exercise price. The number of securities to be issued in column (a) does not include RSUs that are payable solely in cash.
b.Represents securities to be issued under awards assumed in our acquisition of McMoRan Exploration Co. The shares are issuable upon the termination of deferrals with respect to 13,500 RSUs that were vested as of December 31, 2024, and the awards are not reflected in column (b) because they do not have an exercise price.
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The other information required by this item is incorporated by reference to “Stock Ownership of Directors and Executive Officers” and “Stock Ownership of Certain Beneficial Owners” in our definitive proxy statement to be filed with the SEC, relating to our 2025 annual meeting of stockholders.

Item 13.  Certain Relationships and Related Transactions, and Director Independence.

The information required by this item is incorporated by reference to “Certain Transactions” and “Board and Committee Independence; Audit Committee Financial Experts” in our definitive proxy statement to be filed with the SEC, relating to our 2025 annual meeting of stockholders.

Item 14.  Principal Accounting Fees and Services.

The information required by this item is incorporated by reference to “Independent Registered Public Accounting Firm” in our definitive proxy statement to be filed with the SEC (including fees billed to us by Ernst & Young, PCAOB ID No. 42), relating to our 2025 annual meeting of stockholders.

PART IV

Item 15.  Exhibits, Financial Statement Schedules.

(a)(1).                      Financial Statements.

The consolidated statements of income, comprehensive income, cash flows and equity, and the consolidated balance sheets are included as part of Item 8. “Financial Statements and Supplementary Data.”


(a)(2).                      Financial Statement Schedules.

The following financial statement schedule is presented below.

    Schedule II – Valuation and Qualifying Accounts

Schedules other than the one above have been omitted since they are either not required, not applicable or the required information is included in the financial statements or notes thereto.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Freeport-McMoRan Inc.

We have audited the consolidated financial statements of Freeport-McMoRan Inc. (the Company) as of December 31, 2024 and 2023, for each of the three years in the period ended December 31, 2024, and have issued our report thereon dated February 14, 2025 included elsewhere in this Form 10-K. Our audits of the consolidated financial statements included the financial statement schedule listed in Item 15 (a)(2) of this Form 10-K (the “schedule”). This schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s schedule, based on our audits.

In our opinion, the schedule presents fairly, in all material respects, the information set forth therein when considered in conjunction with the consolidated financial statements.

/s/ Ernst & Young LLP

Phoenix, Arizona
February 14, 2025


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SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS (In millions)
  Additions (Deductions)   
 Balance atCharged toCharged to Balance at
 Beginning ofCosts andOtherOther End of
 YearExpenseAccountsDeductions Year
Reserves and allowances deducted      
from asset accounts:      
Valuation allowance for deferred tax assets      
Year Ended December 31, 2024$3,894 $(918)
a
$8 
b
$— 

$2,984 
Year Ended December 31, 20233,985 (80)
c
(11)
b
— 3,894 
Year Ended December 31, 20224,087 (87)
d
(15)
b
— 3,985 
Reserves for non-income taxes:      
Year Ended December 31, 2024$28 $6 $— $(5)
e
$29 
Year Ended December 31, 202324 9 — (5)
e
28 
Year Ended December 31, 202259 (32)— (3)
e
24 
a.Primarily relates to expirations of United States (U.S.) foreign tax credits.
b.Relates to a valuation allowance for tax benefits primarily associated with actuarial losses (gains) for U.S. defined benefit plans included in other comprehensive income.
c.Primarily relates to $32 million of U.S. federal net operating losses (NOLs) utilized during 2023 and a $292 million decrease related to expirations of U.S. foreign tax credits, partially offset by an increase of $188 million, primarily associated with changes in U.S. federal temporary differences and a $22 million increase in valuation allowances against Section 163(j) deferred tax assets.
d.Primarily relates to $163 million of U.S. federal NOLs utilized during 2022 and a $22 million decrease related to expiration of U.S. foreign tax credits, partially offset by an increase of $104 million, primarily associated with changes in U.S. federal temporary differences.
e.Represents amounts paid or adjustments to reserves based on revised estimates.

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(a)(3).                      Exhibits.
  Filed   
Exhibit with thisIncorporated by Reference
NumberExhibit TitleForm 10-KFormFile No.Date Filed
PT-FI Divestment Agreement dated as of September 27, 2018 among FCX, International Support LLC, PT Freeport Indonesia, PT Indocopper Investama and PT Indonesia Asahan Aluminium (Persero).10-Q001-11307-0111/9/2018
Supplemental and Amendment Agreement to the PT-FI Divestment Agreement, dated December 21, 2018, among FCX, PT Freeport Indonesia, PT Indonesia Papua Metal Dan Mineral (f/k/a PT Indocopper Investama), PT Indonesia Asahan Aluminium (Persero) and International Support LLC.10-K001-11307-012/15/2019
Composite Certificate of Incorporation of FCX, effective as of June 11, 2024.  10-Q001-11307-018/7/2024

Amended and Restated By-Laws of FCX, effective as of June 11, 2024. 8-K001-11307-016/12/2024
Description of Common Stock of FCX.10-Q001-11307-018/7/2024
Form of Certificate representing shares of common stock, par value $0.10.8-A/A001-11307-018/10/2015
Indenture dated as of February 13, 2012, between FCX and U.S. Bank National Association, as Trustee (relating to the 5.40% Senior Notes due 2034). 8-K001-11307-012/13/2012
Fourth Supplemental Indenture dated as of May 31, 2013, between FCX and U.S. Bank National Association, as Trustee (relating to the 5.40% Senior Notes due 2034).8-K001-11307-016/3/2013

Eighth Supplemental Indenture dated as of November 14, 2014 between FCX and U.S. Bank National Association, as Trustee (relating to the 5.40% Senior Notes due 2034).
8-K001-11307-0111/14/2014

Indenture dated as of March 7, 2013, between FCX and U.S. Bank National Association, as Trustee (relating to the 5.450% Senior Notes due 2043).8-K001-11307-013/7/2013
Supplemental Indenture dated as of May 31, 2013, between FCX and U.S. Bank National Association, as Trustee (relating to the 5.450% Senior Notes due 2043).
8-K001-11307-016/3/2013
Form of Indenture dated as of September 22, 1997, between Phelps Dodge Corporation and The Chase Manhattan Bank, as Trustee (relating to the 7 1/8% Debentures due 2027, the 9 1/2% Senior Notes due 2031 and the 6 1/8% Senior Notes due 2034).S-3333-364159/25/1997
Form of 7 1/8% Debenture due November 1, 2027 of Phelps Dodge Corporation issued on November 5, 1997, pursuant to the Indenture dated as of September 22, 1997, between Phelps Dodge Corporation and The Chase Manhattan Bank, as Trustee (relating to the 7 1/8% Debentures due 2027).8-K001-0008211/3/1997
Form of 9 1/2% Note due June 1, 2031 of Phelps Dodge Corporation issued on May 30, 2001, pursuant to the Indenture dated as of September 22, 1997, between Phelps Dodge Corporation and First Union National Bank, as successor Trustee (relating to the 9 1/2% Senior Notes due 2031).8-K001-000825/30/2001
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Filed
Exhibitwith thisIncorporated by Reference
NumberExhibit TitleForm 10-KFormFile No.Date Filed
Form of 6 1/8% Note due March 15, 2034 of Phelps Dodge Corporation issued on March 4, 2004, pursuant to the Indenture dated as of September 22, 1997, between Phelps Dodge Corporation and First Union National Bank, as successor Trustee (relating to the 6 1/8% Senior Notes due 2034).10-K001-000823/7/2005
Supplemental Indenture dated as of April 4, 2007 to the Indenture dated as of September 22, 1997, among Phelps Dodge Corporation, as Issuer, Freeport-McMoRan Copper & Gold Inc., as Parent Guarantor, and U.S. Bank National Association, as Trustee (relating to the 7 1/8% Debentures due 2027, the 9 1/2% Senior Notes due 2031 and the 6 1/8% Senior Notes due 2034).10-K001-11307-012/26/2016
Indenture dated as of August 15, 2019, between FCX and U.S. Bank National Association, as Trustee (relating to the 5.00% Senior Notes due 2027, the 4.125% Senior Notes due 2028, the 4.375% Senior Notes due 2028, the 5.25% Senior Notes due 2029, the 4.25% Senior Notes due 2030 and the 4.625% Senior Notes due 2030).
8-K001-11307-01 8/15/2019
First Supplemental Indenture dated as of August 15, 2019, between FCX and U.S. Bank National Association, as Trustee (including the form of 5.00% Senior Notes due 2027).8-K001-11307-018/15/2019
Second Supplemental Indenture dated as of August 15, 2019, between FCX and U.S. Bank National Association, as Trustee (including the form of 5.25% Senior Notes due 2029).
8-K001-11307-018/15/2019
Third Supplemental Indenture dated as of March 4, 2020, between FCX and U.S. Bank National Association, as Trustee (including the form of 4.125% Senior Notes due 2028).8-K001-11307-013/4/2020
Fourth Supplemental Indenture dated as of March 4, 2020, between FCX and U.S. Bank National Association, as Trustee (including the form of 4.25% Senior Notes due 2030).8-K001-11307-013/4/2020
Fifth Supplemental Indenture dated as of March 31, 2020, between FCX and U.S. Bank National Association, as Trustee (relating to the 4.125% Senior Notes due 2028 and the 4.25% Senior Notes due 2030).10-Q001-11307-018/7/2020
Sixth Supplemental Indenture dated as of July 27, 2020, between FCX and U.S. Bank National Association, as Trustee (including the form of 4.375% Senior Notes due 2028).8-K001-11307-017/27/2020
Seventh Supplemental Indenture dated as of July 27, 2020, between FCX and U.S. Bank National Association, as Trustee (including the form of 4.625% Senior Notes due 2030).8-K001-11307-017/27/2020
Shareholders Agreement dated as of December 21, 2018, among FCX, PT Freeport Indonesia, PT Indonesia Papua Metal Dan Mineral and PT Indonesia Asahan Aluminium (Persero).10-K001-11307-012/15/2019
PT Freeport Indonesia Special Mining Business License (IUPK) from the Minister of Energy and Mineral Resources of the Republic of Indonesia (English translation).10-K001-11307-012/15/2019
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Filed
Exhibitwith thisIncorporated by Reference
NumberExhibit TitleForm 10-KFormFile No.Date Filed
Participation Agreement, dated as of March 16, 2005, among Phelps Dodge Corporation, Cyprus Amax Minerals Company, a Delaware corporation, Cyprus Metals Company, a Delaware corporation, Cyprus Climax Metals Company, a Delaware corporation, Sumitomo Corporation, a Japanese corporation, Summit Global Management, B.V., a Dutch corporation, Sumitomo Metal Mining Co., Ltd., a Japanese corporation, Compañia de Minas Buenaventura S.A.A., a Peruvian sociedad anonima abierta, and Sociedad Minera Cerro Verde S.A.A., a Peruvian sociedad anonima abierta.8-K001-000823/22/2005
Shareholders Agreement, dated as of June 1, 2005, among Phelps Dodge Corporation, Cyprus Climax Metals Company, a Delaware corporation, Sumitomo Corporation, a Japanese corporation, Sumitomo Metal Mining Co., Ltd., a Japanese corporation, Summit Global Management B.V., a Dutch corporation, SMM Cerro Verde Netherlands, B.V., a Dutch corporation, Compañia de Minas Buenaventura S.A.A., a Peruvian sociedad anonima abierta, and Sociedad Minera Cerro Verde S.A.A., a Peruvian sociedad anonima abierta.8-K001-000826/7/2005
Revolving Credit Agreement dated as of October 19, 2022, among FCX, PT Freeport Indonesia, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and each of the lenders and issuing banks party thereto.
8-K001-11307-0110/25/2022
Letter Agreement dated as of December 19, 2013, by and between FCX and Richard C. Adkerson.8-K001-11307-0112/23/2013
FCX Director Compensation.10-K001-11307-012/16/2024
Amended and Restated Executive Employment Agreement dated effective as of February 11, 2025 between FCX and Kathleen L. Quirk.X
FCX Executive Services Program.10-K001-11307-012/15/2023
FCX Supplemental Executive Retirement Plan, as amended and restated.8-K001-11307-012/5/2007
FCX 1996 Supplemental Executive Capital Accumulation Plan.10-Q001-11307-015/12/2008
FCX 1996 Supplemental Executive Capital Accumulation Plan Amendment One.10-Q001-11307-015/12/2008
FCX 1996 Supplemental Executive Capital Accumulation Plan Amendment Two.10-K001-11307-012/26/2009
FCX 1996 Supplemental Executive Capital Accumulation Plan Amendment Three.10-K001-11307-012/27/2015
FCX 1996 Supplemental Executive Capital Accumulation Plan Amendment Four.10-K001-11307-012/27/2015
FCX 2005 Supplemental Executive Capital Accumulation Plan, as amended and restated effective January 1, 2015.10-K001-11307-012/27/2015
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Filed
Exhibitwith thisIncorporated by Reference
NumberExhibit TitleForm 10-KFormFile No.Date Filed
FCX 2005 Supplemental Executive Capital Accumulation Plan Amendment One.10-K001-11307-012/16/2021
FCX 2005 Supplemental Executive Capital Accumulation Plan Amendment Two.10-K001-11307-012/16/2021
FCX 2005 Supplemental Executive Capital Accumulation Plan Amendment Three.10-K001-11307-012/16/2021
Freeport Minerals Corporation Supplemental Retirement Plan, as amended and restated.10-K001-11307-012/15/2019
FCX 2004 Director Compensation Plan, as amended and restated. 10-Q001-11307-018/6/2010
FCX Amended and Restated 2006 Stock Incentive Plan.10-K001-11307-012/27/2014
FCX 2016 Stock Incentive Plan.8-K001-11307-016/9/2016
Form of Nonqualified Stock Options Grant Agreement under the FCX stock incentive plans (effective February 2014).10-K001-11307-012/27/2014
Form of Notice of Grant of Restricted Stock Units (for grants made to non-management directors).10-K001-11307-012/24/2017
Form of Performance Share Unit Agreement (effective February 2018).10-K001-11307-012/20/2018
Form of Performance Share Unit Agreement (effective February 2021). 10-K001-11307-012/15/2022
Form of Performance Share Unit Agreement (effective February 2025).X
Form of Nonqualified Stock Options Grant Agreement (effective February 2018).10-K001-11307-012/20/2018
Form of Restricted Stock Unit Agreement (effective February 2018).10-K001-11307-012/20/2018
Form of Restricted Stock Unit Agreement (effective February 2025).X
FCX Annual Incentive Plan (effective January 2019).10-K001-11307-012/15/2019
FCX Executive Change in Control Severance Plan.10-K001-11307-012/15/2022
FCX Insider Trading Policy. X
List of Subsidiaries of FCX.X   
Consent of Ernst & Young LLP.X   
Consents of Qualified Persons for Technical Report Summary of Mineral Reserves and Mineral Resources for Cerro Verde Mine.X   
Consents of Qualified Persons for Technical Report Summary of Mineral Reserves and Mineral Resources for Grasberg Minerals District.X   
Consents of Qualified Persons for Technical Report Summary of Mineral Reserves and Mineral Resources for Morenci Mine.X
Certified resolution of the Board of Directors of FCX authorizing this report to be signed on behalf of any officer or director pursuant to a Power of Attorney.X
Powers of Attorney pursuant to which this report has been signed on behalf of certain officers and directors of FCX.X
Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d - 14(a).X   
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Filed
Exhibitwith thisIncorporated by Reference
NumberExhibit TitleForm 10-KFormFile No.Date Filed
Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d - 14(a).X
Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.X
Certification of Principal Financial Officer pursuant to 18 U.S.C Section 1350.X   
Mine Safety Disclosure.X   
Technical Report Summary of Mineral Reserves and Mineral Resources for Cerro Verde Mine, effective as of December 31, 2024.X
Technical Report Summary of Mineral Reserves and Mineral Resources for Grasberg Minerals District, effective as of December 31, 2022.10-K001-11307-012/15/2023
Technical Report Summary of Mineral Reserves and Mineral Resources for Morenci Mine, effective as of December 31, 2023.10-K001-11307-012/16/2024
FCX Incentive-Based Compensation Recovery Policy, effective as of October 2, 2023.10-K001-11307-012/16/2024
101.INSXBRL Instance Document - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. X   
101.SCHInline XBRL Taxonomy Extension Schema.X   
101.CALInline XBRL Taxonomy Extension Calculation Linkbase.X   
101.DEFInline XBRL Taxonomy Extension Definition Linkbase.X   
101.LABInline XBRL Taxonomy Extension Label Linkbase.X   
101.PREInline XBRL Taxonomy Extension Presentation Linkbase.X   
104
The cover page from this Annual Report on Form 10-K, formatted in Inline XBRL and contained in Exhibit 101.
X
Note:  Certain instruments with respect to long-term debt of FCX have not been filed as exhibits to this Annual Report on Form 10-K since the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of FCX and its subsidiaries on a consolidated basis. FCX agrees to furnish a copy of each such instrument upon request of the United States Securities and Exchange Commission.

*  Indicates management contract or compensatory plan or arrangement.

Item 16.  Form 10-K Summary.

Not applicable.

GLOSSARY OF TERMS
Following is a glossary of selected terms used throughout this Annual Report on Form 10-K that are technical in nature:
Adits. A horizontal passage leading into a mine for the purposes of access or drainage.
Alluvial aquifers. A water-bearing deposit of loosely arranged gravel, sand or silt left behind by a river or other flowing water.
Anode. A positively charged metal sheet, usually lead, on which oxidation occurs. During the electro-refining process, anodes are impure copper sheets from the smelting process that require further processing to produce refined copper cathode.
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Azurite. A bluish supergene copper mineral and ore found in the oxidized portions of copper deposits often associated with malachite.
Bench. The horizontal floor cuttings along which mining progresses in an open-pit mine. As the pit progresses to lower levels, safety benches are left in the walls to catch any falling rock.
Blasthole stoping. An underground mining method that extracts the ore zone in large vertical rooms. The ore is broken by blasting using large-diameter vertical drill holes.
Block cave. A general term used to describe an underground mining method where the extraction of ore depends largely on the action of gravity. By continuously removing a thin horizontal layer at the bottom mining level of the ore column, the vertical support of the ore column is removed and the ore then caves by gravity.
Bornite. A red-brown isometric mineral comprising copper, iron and sulfur.
British thermal unit or Btu. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Brochantite. A greenish-black copper mineral occurring in the oxidation zone of copper sulfide deposits.
Cathode. Refined copper produced by electro-refining of impure copper or by electrowinning.
Chalcocite. A grayish copper sulfide mineral, usually found as a supergene in copper deposits formed from the re-deposition of copper minerals that were solubilized from the oxide portion of the deposit.
Chalcopyrite. A brass-yellow sulfide of mineral copper and iron.
Chrysocolla. A bluish-green to emerald-green oxide copper mineral that forms incrustations and thin seams in oxidized parts of copper-mineral veins; a source of copper and an ornamental stone.
Cobalt. A tough, lustrous, nickel-white or silvery-gray metallic element often associated with nickel and copper ores from which it is obtained as a by-product.
Concentrate. The resulting product from the concentrating process that is composed predominantly of copper sulfide or molybdenum sulfide minerals. Further processing might include smelting and electro-refining, or roasting.
Concentrating. The process by which ore is separated into metal concentrate through crushing, milling and flotation.
Concentrator. A process plant used to separate targeted minerals from gangue and produce a mineral concentrate that can be marketed or processed by additional downstream processes to produce salable metals or mineral products. Term is used interchangeably with Mill.
Contained metal. The amount of metal in a mineral sample before the reduction of amounts unable to be recovered during the metallurgical process.
Covellite. A metallic, indigo-blue supergene mineral found in copper deposits.
Crushed-ore leach pad. A slightly sloping pad upon which leach ores are placed in lifts for processing.
Cutoff grade. The minimum grade contained in the ore for processing. When percentages are below this grade, the material would be routed to an overburden stockpile or left unmined. When percentages are above grade, the material would be processed using concentrating or leaching methods.
Disseminations. A mineral deposit in which the desired minerals occur as scattered particles in the rock that has sufficient quantity to be considered an ore deposit.
Electrolytic refining. The purification of metals by electrolysis. A large piece of impure copper is used as the anode with a thin strip of pure copper as the cathode.
Electrowinning. A process that uses electricity to plate copper contained in an electrolyte solution into copper cathode.
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Flotation. A concentrating process in which valuable minerals attach themselves to bubbles of an oily froth for separation as concentrate. The gangue material from the flotation process reports as a tailing product.
Grade. The relative quality or percentage of metal content.
Indigenous Peoples. Indigenous Peoples are distinct social and cultural groups that share collective ancestral ties to the lands and natural resources where they live, occupy or from which they have been displaced.
Leach stockpiles. A quantity of leachable ore placed on a leach pad or in another suitable location that permits leaching and collection of solutions that contain solubilized metal.
Leaching. The process of extracting copper using a chemical solution to dissolve copper contained in ore.
Malachite. A bright-green copper mineral (ore) that often occurs with azurite in oxidized zones of copper deposits.
Metric ton. The equivalent of 2,204.62 pounds.
Mill stockpile. Millable ore that has been mined, and is available for future processing.
Mine-for-leach. A mining operation focused on mining only leachable ores. Also, referred to as crushed leach.
Mineralization. The process by which a mineral is introduced into a rock, resulting in concentration of minerals that may form a valuable or potentially valuable deposit.
Molybdenite. A black, platy, disulfide of molybdenum. It is the most common ore of molybdenum.
Ore body. A continuous, well-defined mass of mineralized material of sufficient ore content to make extraction economically feasible.
Oxide. In mining, oxide is used as an ore classification relating to material that usually leaches well but does not perform well in a concentrator. Oxide minerals in mining refer to an oxidized form.
Paste backfill. A slurry of paste material produced from tailings with engineered cement and water content that is used to fill underground mined out stopes.
Porphyry. A deposit in which minerals of copper, molybdenum, gold or, less commonly, tungsten and tin are disseminated or occur in stock-work of small veinlets within a large mass of hydro-thermally altered igneous rock. The host rock is commonly an intrusive porphyry, but other rocks intruded by a porphyry can also be hosts for ore minerals.
Production level. With respect to underground mining, the elevation of the underground works that permit extraction/transport of the ore to a common point, shaft or plant.
Pseudomalachite. A dark-green monoclinic copper mineral.
Roasting. The heating of sulfide ores to oxidize sulfides to facilitate further processing.
Run-of-Mine (ROM). Leachable ore that is mined and directly placed on a leach pad without utilizing any further processes to reduce particle size prior to leaching.
Skarn. A Swedish mining term for silicate gangue of certain iron ore and sulfide deposits of Archaean age, particularly those that have replaced limestone and dolomite. Its meaning has been generally expanded to include lime-bearing silicates, of any geologic age, derived from nearly pure limestone and dolomite with the introduction of large amounts of silicon, aluminum, iron and magnesium.
Smelting. The process of melting and oxidizing concentrate to separate copper and precious metals from metallic and non-metallic impurities, including iron, silica, alumina and sulfur.
Solution extraction. A process that transfers copper from a copper-bearing ore to an organic solution, then to an electrolyte. The electrolyte is then pumped to a tankhouse where the copper is extracted, using electricity, into a copper cathode (refer to the term Electrowinning), together referred to as solution extraction/electrowinning (SX/EW).
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Stope. An underground mining method that is usually applied to highly inclined or vertical veins. Ore is extracted by driving horizontally upon it in a series of workings, one immediately over the other. Each horizontal working is called a stope because when a number of them are in progress, each working face under attack assumes the shape of a flight of stairs.
Sulfide. A mineral compound containing sulfur and a metal. Copper sulfides can be concentrated or leached, depending on the mineral type.
Tailings. The crushed and ground material remaining after economically recoverable minerals have been extracted. In upstream design and construction, tailings are deposited on the upstream side of the starter embankment, with subsequent crest raises progressively shifting upstream of each previous raise, using deposited tailings as a foundation. In downstream design and construction, tailings are deposited on the upstream side of the starter embankment. Borrow fill or a portion of the tailings are placed on the downstream side of the starter embankment. Subsequent crest raises progressively shift downstream of each previous raise, such that the previous raise becomes the foundation of the subsequent raise. As a result, the toe and the crest of the embankment progressively shift downstream as the embankment is raised. In centerline design and construction, tailings are deposited on the upstream side of the starter embankment. Borrow fill or a portion of the tailings are placed on the crest of the starter embankment. Subsequent crest raises are constructed vertically along the centerline of the previous raise such that the previous raise becomes the foundation of the subsequent raise. As a result, the toe of the embankment shifts downstream but the crest stays along initial alignment as the embankment is raised.
Tolling. The process of converting customer-owned material into specified products, which is then returned to the customer.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 14, 2025.

Freeport-McMoRan Inc.

By:/s/ Kathleen L. Quirk                                                                                
Kathleen L. Quirk
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 14, 2025.
/s/ Kathleen L. QuirkPresident and Chief Executive Officer
Kathleen L. Quirk(Principal Executive Officer)
/s/ Maree E. RobertsonExecutive Vice President and Chief Financial Officer
Maree E. Robertson(Principal Financial Officer)
*Vice President and Chief Accounting Officer
Ellie L. Mikes(Principal Accounting Officer)
*Chairman of the Board
Richard C. Adkerson
*Director
David P. Abney
*Director
Marcela E. Donadio
*Director
Robert W. Dudley
*Director
Hugh Grant
*Director
Lydia H. Kennard 
*Director
Ryan M. Lance
*Director
Sara Grootwassink Lewis
*Director
Dustan E. McCoy 
*Director
John J. Stephens
*Director
Frances Fragos Townsend 
* By:         /s/ Kathleen L. Quirk           
Kathleen L. Quirk
Attorney-in-Fact
S-1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025
or
☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to            
Commission file number 001-16383
colorlogoonwhitecmyka57.gif
CHENIERE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware95-4352386
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
845 Texas Avenue, Suite 1250
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: 
Title of each classTrading SymbolName of each exchange on which registered
Common Stock, $ 0.003 par valueLNGNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒   No  ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No  ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☒Accelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ 
The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $53.6 billion as of June 30, 2025.
As of February 20, 2026, the issuer had 210,202,883 shares of Common Stock outstanding.
Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.


CHENIERE ENERGY, INC.
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DEFINITIONS

As used in this annual report, the terms listed below have the following meanings: 

Common Industry and Other Terms
ASUAccounting Standards Update
Bcf/dbillion cubic feet per day
Bcf/yrbillion cubic feet per year
Bcfebillion cubic feet equivalent
CAMTcorporate alternative minimum tax
DAPdelivered at place, which requires the buyer to take delivery at one or more designated receiving terminals
DOEU.S. Department of Energy
EPCengineering, procurement and construction
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FIDfinal investment decision
FOBfree-on-board, which requires the buyer to take delivery at seller's export terminal
FTA countriescountries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
GAAPgenerally accepted accounting principles in the U.S.
Henry Hubthe final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
International Climate Change-Related Policiesvalue-chain accountability and sectoral decarbonization standards, including EU Methane Emissions Regulation, FuelEU Maritime Regulation, International Maritime Organization's Net Zero Framework and Corporate Sustainability Due Diligence Directive
IPM agreementsintegrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs
LNGliquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtumillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpamillion tonnes per annum
NGANatural Gas Act of 1938, as amended
NCInon-controlling interests
non-FTA countriescountries with which the U.S. does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SECU.S. Securities and Exchange Commission
SOFRSecured Overnight Financing Rate
SPALNG sale and purchase agreement
TBtu
trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Tcftrillion cubic feet
Trainan industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUAterminal use agreement

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Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2025, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

CEI Org Chart - current.jpg

Unless the context requires otherwise, references to the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, CQP.
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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things: 
•statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements relating to Cheniere’s capital deployment, including intent, ability, extent and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan;
•statements regarding our future sources of liquidity and cash requirements;
•statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
•statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements relating to our goals, commitments and strategies in relation to environmental matters;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•statements regarding our anticipated LNG and natural gas marketing activities;
•any other statements that relate to non-historical or future information; and
•other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this annual report and in the other reports and other information that we file with the SEC. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the
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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.
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PART I

ITEMS 1. AND 2.    BUSINESS AND PROPERTIES

General
 
Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

LNG is natural gas (primarily methane) in liquid form and is a cleaner dispatchable fuel for power generation. The LNG we produce is shipped all over the world, converted back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses.

As of December 31, 2025, we were the largest producer of LNG in the U.S. and the second largest LNG operator globally, based on the total production capacity of our natural gas liquefaction facilities. Our total production capacity is expected to be over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 9 mtpa was under construction and the remainder was in operation as of December 31, 2025, comprised of the following:

•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities located in Cameron Parish, Louisiana at Sabine Pass (the “SPL Project”). We own and operate the SPL Project and export facility (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership. As of December 31, 2025, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP. The Sabine Pass LNG Terminal also has five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth, which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own and operate through CQP a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).
•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 9 mtpa under construction and the remainder in operation as of December 31, 2025, from our natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”), of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We also own and operate through CCP an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). The projects under construction at the Corpus Christi LNG Terminal include:
◦a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with over 4 mtpa under construction and the remainder in operation from the first four midscale Trains that have reached substantial completion as of December 31, 2025; and
◦a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “CCL Project”), which was under construction as of December 31, 2025. Our board of directors (our “Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025. Non-FTA export authorization on the CCL Midscale Trains 8 & 9 Project is pending with the DOE.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows, and include SPAs, in which our customers are generally required to pay a fixed fee with respect to the
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contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of December 31, 2025, we have contracted approximately 90% of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us. LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements.

Disciplined Accretive Growth

We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. Our capital allocation plan is designed, in part, to invest in financially disciplined growth accretive to our common stock. Capital investment parameters are the foundation of our disciplined, accretive growth, and include consideration to:

•Achieve value accretive returns through long-term commercial contracts: We aim to contract approximately 90% of our current and planned liquefaction capacity under long-term SPAs and IPM agreements with creditworthy counterparties under the pricing structures described above, with financial parameters that consider, among other things, targeted unlevered returns that exceed our cost of equity and return on stock at prevailing stock prices and project leverage. Our success in securing long-term commercial contracts at desired returns is influenced by global LNG and natural gas market conditions and other uncertainties described in Item 1A. Risk Factors.
•Achieve credit accretive returns: We aim to conservatively fund our projects through financing structures that sustain our long-term, run-rate leverage and credit metrics. Our ability to secure the required financing is influenced by market interest rates and other factors described in Item 1A. Risk Factors.

We have increased available liquefaction capacity at our Liquefaction Projects as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. We are developing a two-phased expansion adjacent to the SPL Project, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate a further expansion of the CCL Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “CCL Expansion Project”). These projects and any future expansions at our sites require, among other things, regulatory approvals and acceptable commercial and financing arrangements before we make a positive FID. Risks associated with cost overruns and delays in the completion of our expansion projects are described in Item 1A. Risk Factors.
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The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL Expansion Project and the CCL Expansion Project:
SPL Expansion Project
CCL Expansion Project
Expected total peak production capacity of LNG (1)
Up to ~ 20 mtpa
Up to 24 mtpa
Milestone
Regulatory (2)
FERC authorizations:
Positive environmental assessmentPendingPending
Order under Section 3 of NGA
PendingPending
Certification to commence constructionPending
DOE export authorization:
FTA countriesü
Non-FTA countriesPending
FinancingFinancing(3)(3)
Commercialization and Other ContractingDefinitive commercial agreements(4)(4)
Definitive full-scope EPC contract
Target Milestone
FID (5)
2026/20272027/2028
ü indicates receipt of authorization, subject to ongoing conditionality

(1)Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval and may change based on design considerations, engagement with contractors and other factors. Subject to adjustment for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities.
(2)Our activities, including our expansion activities, are highly regulated and require regulatory approvals at various stages, including approvals of the FERC and DOE under Sections 3 and 7 of the NGA, as well as several other material governmental and regulatory approvals and permits. The progression of our expansion projects is dependent on receiving all regulatory approvals required within the respective stages. See Item 1A. Risk Factors for further discussion of the regulations under federal, state and local statutes, rules, regulations and laws to which we are subject and associated risk factors relating to regulations.
(3)We anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of this expansion project if we reach a positive FID.
(4)Liquefaction capacity partially contracted by Cheniere Marketing, through SPAs that are conditioned on additional liquefaction capacity beyond what is currently in construction or operation and may be available to be novated to SPL or CCL, and by SPL Stage V, through an IPM agreement.
(5)Expected to be subject to phased FID. Any positive FID is subject to achievement of or consideration to relevant milestones and capital investment parameters described herein.

Our Business Strategy

Our primary business strategy is to be a full-service LNG provider to worldwide end-use customers. We accomplish this objective by owning, constructing and operating LNG and natural gas infrastructure facilities to meet our long-term customers’ energy demands and: 
•safely, efficiently and reliably operating and maintaining our assets;
•procuring natural gas and pipeline transport capacity to our facilities;
•commencing commercial delivery for, and continuing to fulfill all commercial commitments to, our long-term SPA customers;
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•providing value to our customers through destination flexibility, options not to lift cargoes and diversity of price and geography;
•continuing to secure long-term customer contracts to support our planned expansion, including the FID of potential expansion projects beyond the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project;
•completing our construction projects safely, on-time and on-budget;
•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;
•maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply our customers;
•executing our “all of the above” capital allocation strategy, focused on strengthening our balance sheet, funding financially disciplined growth and returning capital to our stockholders; and
•strategically identifying actionable and economic environmental solutions.

Our Business
 
We shipped our first LNG cargo in February 2016 and as of February 20, 2026, over 4,610 cumulative LNG cargoes totaling over 315 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. Our LNG has been shipped to over 40 countries and regions around the world.

Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Sabine Pass LNG Terminal

Liquefaction Facilities and Expansion Project

The Sabine Pass LNG Terminal, as described above under the caption General, is one of the largest LNG production facilities in the world with over 30 mtpa of total production capacity, five storage tanks and three marine berths.

The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the SPL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050:
FERC Approved VolumeDOE Approved Volume
(in Bcf/yr)(in mtpa)(in Bcf/yr)(in mtpa)
FTA countries (1)1,661.94331,661.9433
Non-FTA countries1,661.94331,661.9433
(1)Excludes 950 Bcf/yr to FTA countries authorized in November 2025 for the SPL Expansion Project that is effective for 25 years from the date of first commercial export from the SPL Expansion Project.

In addition, we are developing the SPL Expansion Project, as also described above under the caption General. In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

Natural Gas Supply, Transportation and Storage

SPL has secured a portion of its expected natural gas feedstock for the SPL Project through long-term natural gas supply agreements, including an IPM agreement. SPL Stage V also has an IPM agreement to supply the SPL Expansion Project. Additionally, to ensure that SPL is able to transport and manage the natural gas feedstock to the Sabine Pass LNG Terminal, it
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has transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CTPL.

Regasification Facilities
 
The Sabine Pass LNG Terminal, as described above under the caption General, has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. SPLNG has a long-term, third party TUA for 1 Bcf/d with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), under which TotalEnergies is required to pay fixed monthly fees, whether or not it uses the regasification capacity it has reserved. Approximately 2 Bcf/d of the remaining capacity has been reserved under a TUA by SPL, which also has a partial TUA assignment agreement with TotalEnergies, as further described in Note 12—Revenues of our Notes to Consolidated Financial Statements.

Corpus Christi LNG Terminal

Liquefaction Facilities and Expansion Projects

The Corpus Christi LNG Terminal, as described above under the caption General, has over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 4 mtpa under construction from the Corpus Christi Stage 3 Project, approximately 5 mtpa under construction from the CCL Midscale Trains 8 & 9 Project and the remainder in operation as of December 31, 2025. The Corpus Christi LNG Terminal also includes three storage tanks and two marine berths.

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project as of December 31, 2025:
Corpus Christi Stage 3 ProjectCCL Midscale Trains 8 & 9 Project
Overall project completion percentage94.1%31.8%
Completion percentage of:
Engineering99.6%75.5%
Procurement100.0%47.3%
Subcontract work95.1%29.0%
Construction84.7%0.2%
Date of expected substantial completion1H 2026 - 2H 20262H 2028
The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the CCL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal through December 31, 2050:
FERC Approved Volume (1)DOE Approved Volume (1)
(in Bcf/yr)(in mtpa)(in Bcf/yr)(in mtpa)
Trains 1 through 3 of the CCL Project:
FTA countries875.1617875.1617
Non-FTA countries875.1617875.1617
Corpus Christi Stage 3 Project:
FTA countries582.1411.45582.1411.45
Non-FTA countries582.1411.45582.1411.45
(1)Excludes 170 Bcf/yr to FTA countries authorized in July 2023 for the CCL Midscale Trains 8 & 9 Project that is not effective until the date of first commercial export from the CCL Midscale Trains 8 & 9 Project, which was approved by the FERC in March 2025.

In addition, we are developing the CCL Expansion Project, as also described above under the caption General, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

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Natural Gas Supply, Transportation and Storage

CCL has secured a portion of its expected natural gas feedstock for the Corpus Christi LNG Terminal through long-term natural gas supply agreements, including IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Corpus Christi LNG Terminal, it has transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CCP.

Marketing

LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements. These volumes may be supplemented by volumes procured from third parties at other locations worldwide to support operational requirements or take advantage of market opportunities.

Additional information regarding our marketing activities can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Major Customers

We did not have any customers accounting for 10% or more of total consolidated revenues from contracts with external customers for the year ended December 31, 2025.

Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 20—Segment Information and Customer Concentration of our Notes to Consolidated Financial Statements.

Business Seasonality

Our results are affected by production levels, timing of our maintenance activities and the resulting availability of volumes. Therefore, operating profit may not be generated evenly throughout the year. Weather variations, including temperature, have an impact on LNG output at our Liquefaction Projects. Our Liquefaction Projects are capable of relatively higher production volumes during the cooler months as compared to the summer months. We typically perform our scheduled major maintenance activities at our sites during shoulder months in the second and third quarters in order to mitigate the impact to our annual operating results.

Governmental Regulation
 
Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. As further described in Risks Relating to Regulations within Item 1A. Risk Factors, these rigorous regulatory requirements are built into the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of our liquefaction facilities and the transportation of natural gas in interstate commerce through our pipelines are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:
•rates and charges, and terms and conditions for natural gas transportation, storage and related services;
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•the certification and construction of new facilities and modification of existing facilities;
•the extension and abandonment of services and facilities;
•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;
•the acquisition and abandonment of facilities; and
•various other matters.

Under the NGA, interstate pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including the company’s own affiliates. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require NGA Section 3 LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified the FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process. On March 24, 2022, the FERC rescinded the Policy Statement and re-issued it as a draft. On September 12, 2025, the FERC issued an order terminating the proceeding to consider updates to the 1999 Policy Statement.
We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation.

In order to site, construct and operate our LNG terminals, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.
In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the CCL Midscale Trains 8 & 9 Project. In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities. In December 2025, we filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project by approximately 5 mtpa, which remains pending at the FERC. Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate the CCL Expansion Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) non-discrimination, which requires transmission providers to treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis, and to not make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage; (2) independent functioning, which requires transmission function employees to function independently of marketing function employees; (3) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (4) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.
All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows the imposition of civil and criminal
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penalties for any violations of the NGA and any rules, regulations or orders of the FERC thereunder up to approximately $1.6 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.
Several other governmental and regulatory approvals and permits are required throughout the life of our LNG terminals and our pipelines. In addition, our FERC orders require us to comply with certain ongoing conditions and reporting obligations and maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminals and our pipelines, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.

DOE Export Licenses

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal, as discussed in Sabine Pass LNG Terminal—Liquefaction Facilities, and the Corpus Christi LNG Terminal, as discussed in Corpus Christi LNG Terminal—Liquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Under Section 3 of the NGA, applications for exports of natural gas (including LNG) to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. As part of its review of applications for export of LNG to non-FTA countries, the DOE publishes a Notice of Application in the Federal Register whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. We currently have the SPL Expansion Project and the CCL Midscale Trains 8 & 9 Project pending non-FTA export approval with the DOE. However, the outstanding DOE approval for the SPL Expansion Project is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application. In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s application to the DOE for authorization to export LNG to FTA countries and non-FTA countries. In November 2025, the updated authorization to export LNG to FTA countries was received. See Sabine Pass LNG Terminal and Corpus Christi LNG Terminal sections above for FERC and DOE approved volumes on our existing Liquefaction Projects.

Pipeline and Hazardous Materials Safety Administration

Our LNG terminals as well as the Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $273,000 per day per violation, with a maximum administrative civil penalty of approximately $2.7 million for any related series of violations.

Other Governmental Permits, Approvals and Authorizations

Construction and operation of our facilities require additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the Louisiana Department of Environmental Quality (the “LDEQ”), the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas.

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The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ and LDEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the LDEQ for the Sabine Pass LNG Terminal and CTPL and by the TCEQ for the CCL Project.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Pursuant to the Dodd-Frank Act, the CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

United Kingdom / European Regulations

Our European trading activities, which are primarily established in and operated out of the United Kingdom (“U.K.”), are subject to a number of European Union (“EU”) and U.K. laws and regulations, including but not limited to:
•the European Market Infrastructure Regulation, which was designed to increase the transparency and stability of the European Economic Area (“EEA”) derivatives markets;
•the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”), which prohibits market manipulation and insider trading in EEA wholesale energy markets and imposes various transparency and other obligations on participants active in these markets;
•the Markets in Financial Instruments Directive and Regulation (“MiFID II”), which sets forth a financial services framework across the EEA, including rules for firms engaging in investment services and activities in connection with certain financial instruments, including a range of commodity derivatives; and
•the Market Abuse Regulation, which was implemented to create an enhanced market abuse framework, and which applies generally to all financial instruments listed or traded on EEA trading venues (“Traded Instruments”) as well as other over-the-counter financial instruments priced on, or impacting, the price or value of the Traded Instrument.
Following the U.K.'s departure from the EU (“Brexit”), the EU-wide rules that applied to the U.K. while it was a member of the EU (and during the transition period) have been replicated, subject to certain amendments, to create a parallel set of rules applicable only in the U.K. As a result, we are subject to two separate sets of rules based on the same underlying legislation: (i) one set of rules that apply in the EEA (i.e. not including the U.K.) (the “EEA Rules”); and (ii) one set of rules that apply only in the U.K. (the “U.K. Onshored Rules”). We increasingly are seeing divergence between the EEA Rules and the U.K. Onshored Rules albeit not in a way which is expected to materially impact our business at this time.

To the extent our trading activities have a nexus with the EEA, we comply with the EEA Rules. However, as our trading activities are primarily operated out of the U.K., the main rules that impact and apply to us on a day-to-day basis are the U.K. Onshored Rules.

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In particular, under the U.K. Onshored Rules, firms engaging in investment services and activities under U.K. MiFID II must be authorized unless an exemption applies. We meet the criteria for an exemption and therefore do not need to be authorized under U.K. MiFID II.
In addition to the U.K. Onshored Rules, we are also subject to a separate, U.K.-specific regime that is not based on prior EU/EEA legislation. This is primarily set out in the U.K.’s Financial Services and Markets Act 2000 (“FSMA”) and Financial Services and Markets Act 2000 (Regulated Activities) Order 2001 (“RAO”), which, among other things, governs the regulation of financial services and markets in the U.K., and contains a definitive list of the specified kinds of activities and products that are regulated. Under these U.K.-specific rules, a firm engaging in regulated activities must be authorized unless an exclusion applies. We qualify under applicable exclusions and therefore are not required to be authorized under the U.K. FSMA/RAO regime.

In December 2022, the EU enacted regulations, which among other things established a market correction mechanism against excessively high LNG prices, volatility and movements, and provided for the collection of information though new reporting obligations that would be utilized to provide for a new LNG pricing assessment/benchmark. The applicable regulations are set forth in Council Regulation (EU) 2022/2576-2581. However, these temporary rules have subsequently expired and been replaced by new, yet substantively identical, permanent rules that are within the scope of the recast REMIT regulation which came into effect in May 2024. The impact of such regulations on our business remains uncertain, but is not expected to be material.

Violation of the foregoing laws and regulations could result in investigations, possible fines and penalties, and in some scenarios, criminal offenses, as well as reputational damage.

Brexit and Equivalence

As referenced above, the U.K. ceased to be a member of the EU on January 31, 2020. On December 24, 2020, the EU and the U.K. reached an agreement in principle on the terms of certain agreements and declarations governing the ongoing relationship between the EU and the U.K., including the EU-U.K. Trade and Cooperation Agreement (the “TCA”). The TCA provisionally applied from January 1, 2021, and entered into force on May 1, 2021. The TCA is limited in its scope; in particular the TCA does not make any meaningful provision for the financial services sector. For example, the TCA does not meaningfully address equivalence. Uncertainties remain relating to certain aspects of the U.K.’s future economic, trading and legal relationships with the EU and with other countries. As a result, we separately monitor and ensure compliance with all applicable U.K. and EU rules.

The Financial Services and Markets Act 2023 (“FSMA 2023”) came into U.K. law in June 2023. FSMA 2023 is the framework for the U.K.’s post-Brexit financial legislative and regulatory landscape. It is intended to provide the foundations for a significant overhaul and re-structuring of the U.K. financial services and markets regimes, with many of its measures being intended to address issues and points arising from Brexit. The changes include the revocation of retained EU laws, the introduction of new powers and objectives for the regulators of such markets, as well as a number of measures relevant to financial market infrastructure operators and market participants. Changes will be implemented pursuant to subsidiary legislation or directly by regulators. However, at this time it is not possible to determine whether any such actions would have a material impact on our business.

Environmental Regulation
 
Our LNG terminals are subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

In July 2024, the EU published Regulation (EU) 2024/1787 on the reduction of methane emissions in the energy sector, which became effective on August 4, 2024. This regulation requires, among other things, importers of natural gas (including
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LNG) into the EU to report methane emissions currently and, when and where applicable, to also report information on the measurement, reporting and verification (“MRV”) programs that the producer of such natural gas has in place. In addition, in future years, the EU intends to establish a maximum methane intensity for imported energy and it will be a requirement to demonstrate compliance with this maximum limit. The impact of this regulation on our business is uncertain, but is not expected to be material.
 
Clean Air Act
 
Our LNG terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations or the construction of our Liquefaction Projects.

On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our Liquefaction Projects will be materially and adversely affected by such regulatory actions.
We are supportive of reasonable regulations reducing methane emissions over time. Since 2009, the EPA has promulgated and finalized multiple greenhouse gas (“GHG”) emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376 (P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a waste emissions charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The One Big Beautiful Bill Act (“OBBBA”), signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. We do not believe the methane charge will have a material adverse effect on our operations, financial condition or results of operations.

The timing, extent and impact of these rules and other Biden Administration initiatives remain uncertain as the Trump Administration has undertaken steps to delay their implementation, and to review, repeal and potentially replace them.
Coastal Zone Management Act (“CZMA”)
 
The siting and construction of our LNG terminals within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Louisiana Department of Conservation and Energy, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act
 
Our LNG terminals are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the U.S., including discharges of wastewater and storm water runoff and fill/discharges into waters of the U.S. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.

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Resource Conservation and Recovery Act (“RCRA”)
 
The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If one of our LNG terminals or pipelines adversely affects a protected species or its habitat, we may be required to develop and follow a plan to remediate those impacts. In that case, siting, construction or operations may be delayed or restricted and cause us to incur increased costs.
It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations or the construction of our Liquefaction Projects.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell LNG through Cheniere Marketing or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the EU and elsewhere, the rate of fuel switching from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Significant amounts of money have been invested recently and continue to be invested across Europe and Asia in natural gas projects. In Europe alone, over 50 mtpa of regasification capacity has been added since 2022 with more planned over the next few years to secure access to LNG and displace Russian natural gas imports. In India, over 8,000 kilometers of pipelines have started commissioning in the past several years and there are more than 9,000 kilometers of natural gas pipelines under construction to expand the natural gas distribution network and increase access to natural gas. And in China, hundreds of billions of U.S. dollars have been and are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.

As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2025, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 64%, from approximately 410 mtpa, or 19.7 Tcf, in 2024, to 671 mtpa, or 32.2 Tcf, in 2040 and by approximately 67% to 685 mtpa or 32.9 Tcf in 2050. WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 568 mtpa in 2040, declining to about 472 mtpa in 2050. This could result in a market need for construction of an additional approximately 104 mtpa of LNG production by 2040 and about 212 mtpa by 2050. As a cleaner dispatchable fuel for power generation, we expect natural gas and LNG to play a central role in balancing grids and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Projects, as well as our proposed expansions at Sabine Pass and Corpus Christi, are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.
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As described above under the caption General, we have limited exposure to oil price movements and other competing fuels as we have contracted a significant portion of our LNG production capacity under long-term SPAs and IPM agreements, which are structured to generate fixed fees in addition to variable fees indexed to Henry Hub or international LNG pricing. Refer to General for further discussion of our long-term agreements.

Competition

Despite the long term nature of our SPAs, when SPL, CCL or Cheniere Marketing need to replace or amend any existing SPA or enter into new SPAs, they will compete with each other and other natural gas liquefaction projects throughout the world primarily on the basis of price per contracted volume of LNG at that time, as well as attributes such as commercial innovation, reliable production and customer-focused operations to provide flexible and tailored solutions to LNG buyers. Revenues associated with any incremental volumes sold outside of our long-term SPAs, including those sold by our integrated marketing function, will also be subject to market-based price competition. Refer to Item 1A. Risk Factors for further discussion of risks relating to market competition.

Corporate Responsibility

As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges — expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2025, we published Together, We Deliver, our sixth Corporate Responsibility (“CR”) report, which details our approach and progress on environmental, social and governance (“ESG”) matters. Our CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K. For further discussion on social and governance matters, see Human Capital Resources.

Our climate strategy is to measure and mitigate emissions so that we may better position our LNG supplies to remain competitive in a lower carbon future and provide energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop our climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain. In 2024, we announced a voluntary, measurement-informed Scope 1 annual methane emissions intensity target across our liquefaction facilities. The Scope 1 methane target builds upon our robust climate strategy and leverages data from our multi-scale quantification, monitoring, reporting and verification (“QMRV”) emissions measurement program. We achieved a methane emissions intensity for 2024, which received third party limited assurance, of less than our methane target of 0.03% across our liquefaction sites, as reported in our latest CR report.

As a key aspect of our strategy, we collaborate with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, QMRV of GHG emissions and other research and development projects. We also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, we commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative. As a result of our efforts described above, in 2025, we achieved OGMP 2.0 Gold Standard reporting by the UNEP for our comprehensive methane emissions measurement and reporting under the OGMP 2.0 program and recognition by the Coalition for LNG Emissions Abatement toward Net-zero led by the Japan Organization for Metals and Energy Security. To ensure transparency and rigor, we work with academics and scientists to publish methodologies and results in multiple peer-reviewed journals.

Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the years ended December 31, 2025, 2024 and 2023. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives
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to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.

Human Capital Resources

We are in a unique position as the largest producer of liquefied natural gas in the U.S. and the second-largest LNG operator globally. As an industry leader, we invest in core human capital priorities — attracting, engaging, retaining and developing talent — because our employees enable our current and future success and our ability to generate long-term value.
 
Our employees help drive our success, build our reputation, establish our legacy and deliver on our commitments to our customers. We aim to retain the best talent and keep our employees engaged through fulfilling career opportunities, training and development resources, and a competitive compensation program.

Our Chief Human Resources Officer oversees human capital management. This includes our approach to talent attraction and retention, rewards and remuneration, employee relations, employee engagement and training and development. Both our Chief Human Resources Officer and Chief Compliance and Ethics Officer communicate progress on our programs to our Board quarterly. 

As of December 31, 2025, we had 1,717 full-time employees with 1,617 located in the U.S. and 100 located outside of the U.S. (primarily in the U.K.).
Talent Attraction and Retention

Our recruitment strategy is focused on attracting highly skilled talent. We offer competitive compensation and benefits, and work to develop and attract a strong talent pipeline through a range of internship, apprenticeship and vocational programs. We invest in opportunities to help local students and communities gain specialized skills and create local jobs through sponsorship of apprenticeships and internships. On an annual basis, we participate in workforce availability studies in the geographic areas where we operate to align our workforce planning with available community resources and talent. Internally and externally, we post openings to attract individuals with a range of qualified backgrounds, skills and experience. Our voluntary turnover was 5.5% for 2025.

Compensation and Benefits

We provide robust compensation and benefits programs to our employees. In addition to salaries, all employees are eligible for annual bonuses and stock awards. Benefit plans, which vary by country, include a 401(k) plan, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, family care resources, employee assistance programs and tuition assistance. We link our annual incentive program to financial and non-financial performance metrics.

Culture and Engagement

We are committed to supporting a culture where all employees can thrive, feel they belong and are valued. To create this environment, we are committed to compliance with all federal, state and local laws that prohibit workplace discrimination, harassment and unlawful retaliation. Our Code of Business Conduct and Ethics, our core values of teamwork, respect, accountability, integrity, nimble and safety (“TRAINS”) and our policies demonstrate our commitment to building an inclusive workplace, regardless of race, beliefs, nationality, gender and sexual orientation or any other legally protected characteristics. We are committed to providing fair and equitable employee programs including compensation and benefits.

We manage and measure organizational health with a view to gaining insight into employees’ experiences, levels of workplace satisfaction and feelings of engagement and inclusion with the company. Employees are encouraged to share ideas and concerns through multiple feedback channels, including direct feedback to management and Human Resources business partners, town halls and hotlines which can be reached anonymously. Insights from these channels are used to develop both company-wide and business unit level talent development plans and training programs.
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Development and Training

Our apprenticeship program prepares local students for careers in LNG. This program combines classroom education with training and on-site learning experiences at our facilities.

We strive to provide our people with all of the tools and support necessary for them to succeed. We actively encourage our employees to take ownership of their careers and offer a number of resources to do so. Employees receive mid-year and annual performance reviews, as well as frequent informal discussions to help meet their career goals. We also conduct annual talent reviews and succession planning sessions to ensure future organizational talent trends are met. To ensure safe, reliable and efficient operations in a highly regulated environment, we offer online and site-specific learning opportunities. We also provide employees, leaders and executives with targeted development programming to solidify internal talent pipelines and succession plans.

Employee Safety, Health and Wellness

The safety of our employees, contractors and communities is one of our core values, and is carried out through our required safety programs and safety and health related procedures. Safety efforts are led by our Executive Safety Committee, which includes the Chief Executive Officer, senior leaders from across the company and representatives from our sites. We focus our efforts on continuously improving our performance. For the year ended December 31, 2025, we had no employee recordable injuries and 21 contractor recordable injuries. Our total recordable incident rate (employees and contractors combined) was 0.20, placing us in the top quintile of industry benchmarks based on Bureau of Labor safety statistics.

To support the well-being of our employees, we provide a wellness program that offers employees incentives to maintain an active lifestyle and set personal wellness goals. Incentives include online education related to health, nutrition and emotional health, as well as subsidies for fitness devices and gym memberships. We also offer mammography screenings, rooms for nursing mothers and biometric screenings.

Subsidiaries
 
Substantially all of our assets are held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction, maintenance and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.

Available Information

Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 845 Texas Avenue Suite 1250, Houston, Texas 77002 or call (713) 375-5000. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers.
Additionally, we encourage you to review our CR Report (located on our internet site at www.cheniere.com), for more detailed information regarding our Human Capital programs and initiatives, as well as our initiatives and metrics related to ESG. Nothing on our website, including our CR Report or sections thereof, shall be deemed incorporated by reference into this Annual Report.

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ITEM 1A.    RISK FACTORS
 
The following are some of the important factors that should be considered when investing in us, as such risk factors could adversely affect our business, financial condition, results of operations or cash flows or have other adverse impacts, and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
•Risks Relating to Our Financial Matters;
•Risks Relating to Our Operations and Industry; and
•Risks Relating to Regulations.
Risks Relating to Our Financial Matters
 
An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect us.

As of December 31, 2025, we had, on a consolidated basis, $1.1 billion of cash and cash equivalents (of which $182 million was held by our consolidated variable interest entities (“VIEs”)), $485 million of restricted cash and cash equivalents (of which $22 million was held by our VIEs), a total of $7.2 billion of available commitments under our credit facilities and $23.0 billion of total debt outstanding (before unamortized discount and debt issuance costs). SPL, CQP, CCH and Cheniere operate with independent capital structures as further detailed in Note 10—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as well as the SPL Expansion Project and the CCL Expansion Project if positive FIDs are made on these expansion projects. Our ability to fund our capital expenditures and refinance our indebtedness may depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also may rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement lenders or seek alternative financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant portion of our customers fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2025, we had SPAs with initial terms of 10 or more years with approximately 30 different third party customers, with customers under common control being considered a single customer.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.
Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure.
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Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

We and our subsidiaries may be restricted under the terms of our and their indebtedness from paying dividends or distributions under certain circumstances, which could materially and adversely affect our liquidity.

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay dividends or distributions. For example, CCH and SPL are restricted from making distributions under agreements governing their indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical and projected debt service coverage ratio of 1.25:1.00 is satisfied.
In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm before making a distribution that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a certain specified date.

Any inability to pay or increase dividends or distributions by us or our subsidiaries as a result of the foregoing restrictions could have a material adverse effect on our liquidity.

Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.

In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, as further described in the immediately preceding risk factor, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to:
•make certain investments;
•purchase, redeem or retire equity interests;
•issue preferred stock;
•sell or transfer assets;
•incur liens;
•enter into transactions with affiliates;
•consolidate, merge, sell or lease all or substantially all of our assets; and
•enter into sale and leaseback transactions.

Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.

Our use of derivative instruments, including our IPM agreements, to manage risks could have a significant adverse or otherwise volatile effect on our earnings reported under GAAP and our liquidity.

We use derivative instruments to manage certain risks, including commodity-related price risk. The extent of our derivative position at any given time depends on our assessment of risks and related exposures for these commodities. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse or otherwise volatile effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the years ended December 31, 2025 and 2024 included $3.6 billion and $1.3 billion of gains, respectively, resulting from changes in the fair values of our derivatives (before
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tax and the impact of non-controlling interests), substantially all of which were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.

These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, our liquidity may be adversely impacted by the cash margin requirements of the respective commodity exchanges or over-the-counter arrangements. As of December 31, 2025 and 2024, we had collateral posted with counterparties by us of $76 million and $128 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.

Dividends are authorized and determined by our Board in its sole discretion and depend upon a number of factors, including:
•Cash available for distribution;
•Our results of operations and anticipated future results of operations;
•Our financial condition, especially in relation to the anticipated future capital needs of any expansion of our liquefaction facilities;
•The level of distributions paid by comparable companies;
•Our operating expenses; and
•Other factors our Board deems relevant.

We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our dividend or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities, after deducting capital expenditures, investments and other commitments, are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.
Additionally as of December 31, 2025, $1.2 billion of repurchase authority remained under our share repurchase program authorized by our Board, which subsequently increased to approximately $10 billion from 2026 through 2030 after a $9 billion increase was authorized in February 2026. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may consider when declaring dividends, among others.

Any downward revision in the amount of dividends we pay to stockholders or the number of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.

Risks Relating to Our Operations and Industry
 
Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.

Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or
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interruption of operations at our terminals or related infrastructure, or interruptions to our power supply, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of our Liquefaction Projects or our other facilities. Our LNG terminal infrastructure and LNG facilities are designed in accordance with the requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or for transporters to continue shipping natural gas to us from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the immediately preceding risk factor. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Projects to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the immediately preceding risk factor. Additionally, composition changes in the quality of feed gas received from third parties may impact operational efficiency and performance, which could have an effect on our operating results. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals and our pipelines are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self-insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project.

Timely and cost-effective completion of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
•design and engineer each Train to operate in accordance with specifications;
•engage and retain third party subcontractors and procure equipment and supplies;
•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
•attract, develop and retain skilled personnel, including engineers;
•post required construction bonds and comply with the terms thereof;
•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
•maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential expansion projects, including the SPL Expansion Project and the CCL Expansion Project, or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the construction of our expansion projects, including the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and the CCL Expansion Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our investment decision on the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and any potential future expansion of LNG facilities, including the SPL Expansion Project and the CCL Expansion Project, relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope and the ability of Bechtel and our other contractors to execute successfully under their agreements. Although our major EPC contracts are fixed price, as construction progresses, we may decide or be forced to submit change orders to our contractor, including change orders to comply with existing or future environmental or other regulations. Any change orders could result in longer construction periods, higher construction costs, including increased commodity prices (particularly nickel and steel) and escalating labor costs, or both. Additionally, certain of our SPAs provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
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Significant increases in the cost of a liquefaction project or significant construction delays could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our ability to complete development and/or construction of additional Trains, including the SPL Expansion Project and the CCL Expansion Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our growth strategy.

We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the SPL Expansion Project and the CCL Expansion Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.

We will require significant additional funding to be able to commence construction of the SPL Expansion Project, the CCL Expansion Project and any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the SPL Expansion Project, the CCL Expansion Project or any additional expansion projects, which could have a material adverse effect on our growth strategy, financial condition, operating results, cash flow and liquidity.

There may be impediments to the transport of LNG to customers, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We sell a significant amount of our LNG under DAP terms requiring delivery to international destinations. To fulfill our transportation requirements under these arrangements, including those under long term SPAs, we depend on the ability to secure chartered vessels often through long term lease arrangements. The construction and delivery of LNG vessels require significant capital and long construction lead times, and we may execute charters several years before the lease arrangements commence.

Although we actively manage our vessel requirements in response to the market and our customer contracts, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers because of:
•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
•shortages of or delays in the receipt of necessary construction materials;
•political or economic disturbances;
•acts of war or piracy;
•changes in governmental regulations or maritime self-regulatory organizations’ regulations;
•work stoppages or other labor disturbances;
•bankruptcy or other financial crisis of shipbuilders or shipowners;
•quality or engineering problems;
•disruptions to maritime transportation routes, such as the security situation in the Gulf of Aden and congestion at the Panama Canal; and
•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.

While our chartered vessels are operated by the ship owners and we are exposed to risks outside of our own control, we are generally protected through provisions in our charter agreements from transportation disruptions on the part of the ship
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owner, including disruptions due to off-hire and downtime periods or shipping delays. However, other events outside of our control where we may not be protected may have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Additionally, while our vessel charters allow us to secure fixed rates under long term contracts (in certain cases subject to inflation) and we generally structure our SPAs to recover increase in such costs, our profitability, particularly relating to our short term or spot LNG sales outside of our SPAs, is largely dependent on the strength of international LNG markets. While historical downturns have not had a material adverse impact to our operations or results, any prolonged weakening of such markets could result in depressed or negative margins. See the risk factor Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects for additional discussion.

Changes to U.S. trade policy could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The U.S. has recently enacted and proposed to enact significant new tariffs and trade restrictions. Additionally, President Trump has directed various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion and commentary regarding potential significant changes to U.S. trade policies, treaties and tariffs. For example, as part of its Section 301 investigation of the maritime, logistics and shipbuilding sector in China (the “Section 301 Investigation”), the Office of the U.S. Trade Representative (the “USTR”) in April 2025 mandated, among other things, restrictions on maritime transport services for U.S. LNG exports. These measures require that, beginning in April 2029, 1% of U.S. LNG exports must be exported on U.S.-built vessels, with such percentage gradually increasing to 15% in April 2047, with certain exceptions. In its original April 2025 notice, USTR had included the potential suspension of LNG export licenses as a remedy for non-compliance with the U.S. vessel restrictions; however, USTR subsequently removed the suspension language. In November 2025, the White House announced that, as part of the broader economic and trade relations deal with China, it had agreed to defer certain pending tariff and trade measures against China, including suspending for one year the implementation of fees on China-linked vessels pursuant to the Section 301 Investigation. However, the timeline for the U.S.-built vessel requirements for U.S. LNG exports thus far has not been modified. Given the ongoing evolution of the Section 301 Investigation measures, the potential impact of the restrictions on us and the LNG industry remains uncertain.

There continues to exist significant uncertainty about the future relationship between the U.S. and other countries with respect to trade policies, trade agreements, trade restrictions and tariffs. Any resulting unwillingness or inability of LNG purchasers in such countries to import LNG from the U.S. or increases in pricing as a result of retaliatory tariffs on exported U.S. LNG, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
•increasingly competitive North American LNG landscape;
•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
•insufficient LNG tanker capacity;
•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;
•reduced demand and lower prices for natural gas worldwide;
•increased demand for natural gas in North America;
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•increased natural gas production worldwide, either domestically or deliverable by pipelines, which could suppress demand for LNG;
•decreased oil and natural gas exploration activities which may decrease the production of natural gas in North America;
•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;
•changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;
•changes in regulatory, tax or other governmental policies regarding exported North American LNG, natural gas or alternative energy sources, which may reduce the demand for exported North American LNG and/or natural gas;
•political conditions in customer regions;
•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;
•adverse relative demand for North American LNG compared to other sources, which may decrease LNG exports from North America; and
•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our LNG business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from North America, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside North America, which could increase the available supply of natural gas outside North America and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the U.S. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the U.S.

As described in Market Factors and Competition in Items 1. and 2. Business and Properties, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from North America, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in North America.

As described in General in Items 1. and 2. Business and Properties, as of December 31, 2025, we have contracted through our SPAs and IPM agreements approximately 90% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long
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term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the U.S. could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.
    
Our Liquefaction Projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others:
•increases in worldwide LNG production capacity and availability of LNG for market supply;
•decreases in demand for LNG or increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
•increases in the cost to supply natural gas feedstock to our Liquefaction Projects;
•increases in the cost to supply power to our Liquefaction Projects;
•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
•increases in capacity and utilization of nuclear power and related facilities; and
•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

A cyberattack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyberattacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyberattacks, including third party pipelines which supply natural gas to our Liquefaction Projects. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should multiple of the third party pipelines which supply our Liquefaction Projects suffer similar concurrent attacks, our Liquefaction Projects may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyberattack involving our business or operational control systems or related infrastructure, or that of third parties pipelines with whom we do business, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. In the U.S., we are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in
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applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term, other than our employment agreement with our President and Chief Executive Officer. The loss of the services of any of these individuals could have a material adverse effect on our business.

Outbreaks of infectious diseases, such as COVID-19, at one or more of our facilities could adversely affect our operations or business.

Our facilities at the Sabine Pass LNG Terminal and Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown and the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations or business.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of interstate natural gas pipelines, Trains, including those at the Liquefaction Projects, the SPL Expansion Project, the CCL Expansion Project and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of all of our Trains in operation or under construction, as well as orders under Section 7 of the NGA authorizing the construction and operation of all of our pipelines in operation or under construction. In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project and in June 2025, certain of our subsidiaries submitted an updated application to the FERC reflecting a two-phased approach to the SPL Expansion Project. In December 2025, we filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project by approximately 5 mtpa and the application remains pending at the FERC. Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate the CCL Expansion Project in a phased approach.

To date, the DOE has also issued orders under Section 3 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG, as further detailed in DOE Export Licenses in Our Business. We currently have the SPL Expansion Project and the CCL Midscale Trains 8 & 9 Project pending non-FTA export approval with the DOE. However, non-FTA export approval for the SPL Expansion Project is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown,
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political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. The FERC’s jurisdiction under the NGA allows the imposition of civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC thereunder, up to $1.6 million per day for each violation.

Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
    
Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals, marine berths and pipelines, including FERC, PHMSA, EPA and the U.S. Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
    
The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that would have applied to our facilities beginning in calendar year 2024. The OBBBA, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

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Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

In 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY beginning in 2022.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or International Climate Change-Related Policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2025, 2024 and 2023. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
•perform ongoing assessments of pipeline safety and compliance;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.

We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.
Additions or changes in tax laws and regulations or variables impacting our tax obligations could potentially affect our financial results or liquidity.

Tax laws and regulations are complex and rapidly evolving. We are subject to various taxes in the jurisdictions where we operate. Changes to local, state, domestic or international tax laws, their interpretation, enforcement practices and rates, including changes related to tariffs and duties, are beyond our control and could affect our tax obligations, compliance costs, financial results and cash flows. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

Additionally, we have ad valorem legacy property tax incentives secured for the Corpus Christi LNG Terminal, inclusive of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, and the Sabine Pass LNG Terminal that begin to expire starting in 2026 and 2027, respectively, with continuing incentive roll-off thereafter over the longer term. The magnitude of property tax changes once our incentives expire is uncertain, but will be influenced, both in the near and longer term, by various factors including future local tax rates, local tax rate compression dynamics and variation in our assessed
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property values over time. During the year ended December 31, 2025, our ad valorem property tax incurred was approximately $89 million across the Cheniere complex.

ITEM 1B.    UNRESOLVED STAFF COMMENTS
 
None.

ITEM 1C.    CYBERSECURITY

Cyberattacks represent a potentially significant risk to the Company and our industry. We have implemented policies and procedures that are intended to manage and reduce this risk.

Risk Management and Strategy

As part of our broader approach to risk management, our cybersecurity program is designed to follow a “govern, identify, protect, detect, respond and recover” approach to cybersecurity that is based on the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Our strategy also includes segmentation of corporate and operations networks, defense in depth and the principle of least privilege. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks. We include business continuity planning as a component of our strategy to help ensure critical systems are available to support our company in the instance of a disruptive event. We also participate in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, we assess our people, processes and technology and, when necessary, adjust the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. We conduct regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance our Cybersecurity Incident Response Plan. To support these efforts, we have contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems and security maturity assessments of our corporate and operational networks. We maintain a training program to help our personnel identify and assist in mitigating cybersecurity and data security risks. Our employees and Board members participate in periodic training, user awareness campaigns and additional issue-specific training as needed. We also provide periodic training for certain contractors who have access to our information technology networks.

With respect to third party service providers, our information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. We seek to contractually require third party service providers with access to our information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use our data, including personal information, for purposes other than to provide services to us, except as required by applicable law. We also seek to negotiate contractual requirements which compel our service providers to notify us of information security incidents occurring on their systems which may affect our systems or data, including personal information.
During the year ended December 31, 2025, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.

Governance

Our cybersecurity leadership team consists of our Director and Chief Information Security Officer, Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of our cybersecurity governance, cyber risk management and security operations and are responsible for maintaining our technology defense posture and program. As part of their governance and risk management responsibilities, these individuals oversee the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents, including the systems deployed in our technology infrastructure to monitor for threats, perform security control testing and assessments, and incorporate threat intelligence into our day-to-day cybersecurity operations and strategic initiatives. They have decades of
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experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats.

Risks that could affect us are an integral part of our Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into our enterprise risk assessment process, which is reviewed by our Board at least annually. Our Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee has been delegated the authority to oversee and periodically review the security of our information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with management our cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including our risk assessment and risk management policies. On a quarterly basis, our cybersecurity leadership team updates the Audit Committee on the overall status of our cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

For additional information about cybersecurity risks, see the risk A cyberattack involving our business, operational control systems or related infrastructure, or that of third parties with whom we do business, including pipelines which supply our Liquefaction Projects, or an attack on our critical suppliers, could negatively impact our business or operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting and potentially harm our reputation under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.

ITEM 3. LEGAL PROCEEDINGS

We are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

LDEQ Matter

We are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022, we petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The EPA approved the petition on July 31, 2025 and in October 2025 the LDEQ confirmed that all remaining milestones under the 2023 Compliance Order have been met. We continue to work with the LDEQ to resolve the 2023 Compliance Order. As of December 2025, we had filed test results with the LDEQ indicating that for the 2025 testing period all 44 turbines met the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

ITEM 4.    MINE SAFETY DISCLOSURE

Not applicable.
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PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information, Holders and Dividend Policy

Our common stock has traded on the New York Stock Exchange under the symbol “LNG” since February 5, 2024, and previously traded on the NYSE American or its predecessors under the symbol “LNG” from March 24, 2003 through February 3, 2024. As of February 20, 2026, we had approximately 210.2 million shares of common stock outstanding held by 69 record owners. Because our shares are held by brokers and other institutions on behalf of our stockholders, we are unable to estimate the total number of actual stockholders represented by these record owners.

We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time. The declaration of dividends is subject to the discretion of our Board, and will depend on our financial condition and other factors deemed relevant by our Board. See the risk Our ability to declare and pay dividends and repurchase shares is subject to certain considerations under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended December 31, 2025:
PeriodTotal Number of Shares PurchasedAverage Price Paid Per Share (1)Total Number of Shares Purchased as a Part of Publicly Announced PlansApproximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (in millions) (2)
October 1 - 31, 20252,561,225$224.252,561,225$1,642
November 1 - 30, 20251,063,305$209.911,063,305$1,418
December 1 - 31, 20251,143,924$190.841,143,924$1,200
Total4,768,4544,768,454
(1)Average price excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.
(2)In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. See Note 18—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs.

Total Stockholder Return

The following is a customized peer group consisting of 17 companies (the “Peer Group”) that were selected because they are publicly traded companies that have comparable Global Industry Classification Standards. We also took into consideration those companies that have similar market capitalization, enterprise values, operating characteristics and capital intensity.
Peer Group
Air Products and Chemicals, Inc. (APD)
Marathon Petroleum Corporation (MPC)
Baker Hughes Company (BKR)
Occidental Petroleum Corporation (OXY)
ConocoPhillips (COP)
ONEOK, Inc. (OKE)
Enterprise Products Partners L.P. (EPD)
Phillips 66 (PSX)
EOG Resources, Inc. (EOG)Suncor Energy Inc. (SU)
Halliburton Company (HAL)Targa Resources Corp. (TRGP)
Hess Corporation (HES)Valero Energy Corporation (VLO)
Kinder Morgan, Inc. (KMI)
The Williams Companies, Inc. (WMB)
LyondellBasell Industries N.V. (LYB)

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The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index and our Peer Group on December 31, 2020 and that any dividends were fully reinvested.
December 31,
Company / Index202020212022202320242025
Cheniere Energy, Inc.$100.00 $169.48 $253.08 $291.07 $370.15 $337.99 
S&P 500 Index100.00 128.68 105.35 133.02 166.27 195.96 
Peer Group (1)100.00 144.60 214.66 235.62 273.47 284.95 
(1)Includes Hess Corporation (HES) through end of trading on July 17, 2025. On July 18, 2025, HES was acquired by Chevron Corporation and its common stock was suspended from trading on the New York Stock Exchange prior to opening of trading.
2106

ITEM 6.    [Reserved]
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ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Introduction
 
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Discussion of items for the year ended December 31, 2023 and variance drivers between the year ended December 31, 2024 as compared to December 31, 2023 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2024.

Our discussion and analysis includes the following subjects: 
•Overview
•Overview of Significant Events
•Market Environment
•Results of Operations
•Liquidity and Capital Resources
•Summary of Critical Accounting Estimates
•Recent Accounting Standards

Overview
 
We are an energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas. Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. For further discussion of our business, see Items 1. and 2. Business and Properties.

During 2025, we continued to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, as well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future. The continued strength and stability of our long-term cash flows served as the foundation of our updated comprehensive, long-term capital allocation plan announced in June 2024, which includes an increased share repurchase authorization and increased dividends, in addition to a continued decrease in consolidated long-term leverage and investment in accretive organic growth.

Overview of Significant Events

Our significant events since January 1, 2025 and through the filing date of this Form 10-K include the following:

Strategic

Growth
•Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate in a phased approach the CCL Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
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•In December 2025, we filed an application with the FERC to increase the LNG production capacity of the previously-authorized Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project by approximately 5 mtpa, which remains pending at the FERC.
•In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the CCL Midscale Trains 8 & 9 Project, and in June 2025, our Board made a positive FID with respect to the investment in the development, construction and operation of the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under a fixed price separated turnkey EPC contract.
•In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
Commercialization
•In August 2025, Cheniere announced the execution of a long-term LNG SPA between Cheniere Marketing and JERA Co., Inc. (“JERA”), under which JERA has agreed to purchase approximately 1 mtpa of LNG from Cheniere Marketing on an FOB basis from 2029 through 2050. The purchase price for LNG under the SPA is indexed to the Henry Hub price, plus a fixed liquefaction fee.
•In May 2025, Cheniere Marketing entered into an IPM agreement with Canadian Natural Resources Limited to purchase 140,000 MMBtu per day of natural gas at a price based on the Japan Korea Marker, less fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing in 2030.

Operational

•As of February 20, 2026, over 4,610 cumulative LNG cargoes totaling over 315 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
•In March, August, October and December 2025, substantial completions of Trains 1, 2 3 and 4, respectively, of the Corpus Christi Stage 3 Project were achieved. In February 2026, LNG was produced for the first time from Train 5 of the Corpus Christi Stage 3 Project.
•During the second quarter of 2025, we completed planned large-scale maintenance activities on two Trains at the SPL Project.

Financial

•In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization.
•In February 2026, SPL redeemed the remaining $200 million aggregate principal amount of its 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”).
•In August 2025, we amended and restated our $1.25 billion Cheniere Revolving Credit Facility to, among other things, (1) extend the maturity date thereunder, (2) reduce the interest rate and commitment fees payable thereunder and (3) make certain other changes to the terms and conditions of the existing Cheniere Revolving Credit Facility.
•In July 2025, CQP issued and sold $1.0 billion aggregate principal amount of 5.550% Senior Notes due 2035 (the “2035 CQP Senior Notes”), and the net proceeds, together with cash on hand, were used to redeem $1.0 billion of the aggregate principal amount of SPL’s 2026 SPL Senior Notes.
•In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share, which commenced with the dividend pertaining to the third quarter of 2025.
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•We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”) and Fitch Ratings (“Fitch”):

EntityDatePrevious RatingUpgraded RatingRating AgencyOutlook
CheniereNovember 2025BBBBBB+S&PStable
CQPNovember 2025BBBBBB+S&PStable
CCHOctober 2025BBBBBB+S&PPositive
CheniereFebruary 2025BBB-BBBFitchStable
CQPFebruary 2025BBB-BBBFitchStable

•In addition to the above issuer credit rating upgrades, the unsecured CQP Notes were upgraded from BBB- to BBB by S&P in June 2025, concurrent with the assignment of the 2035 CQP Senior Notes credit rating. S&P also revised its outlook on SPL to positive from stable in December 2025.
•During the year ended December 31, 2025, we accomplished the following pursuant to our capital allocation priorities:
◦We repurchased approximately 12.1 million shares of our common stock as part of our share repurchase program for approximately $2.7 billion.
◦We redeemed and repaid $652 million aggregate principal amount of notes across our complex, comprised of the following:
▪In December 2025, SPL redeemed $300 million aggregate principal amount of its 2026 SPL Senior Notes.
▪In September 2025, SPL repaid $52 million aggregate principal amount outstanding of its series of senior secured notes due 2037 with a weighted average interest rate of 4.746%, based on their respective fixed amortization schedules.
▪In March 2025, SPL repaid the remaining $300 million aggregate principal amount outstanding of its 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”) at maturity.
◦We paid dividends of $2.055 per share of common stock during the year ended December 31, 2025.
◦We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Market Environment

Our results of operations are affected by the market environment in which we operate, including known trends and uncertainties, macroeconomic factors and other external environmental factors.

With just under 20 mtpa of year on year (“YoY”) increase in LNG supplies globally in 2025, the LNG market is transitioning from a multi-year state of tight market conditions into a period of rapid growth. The continued ramp up in new LNG supplies from the U.S. and Canada mark the start of a more ample supply landscape which is expected to loosen global balances over the next few years and result in a more moderate and stable price environment for LNG. Sustained downward pressure on global prices could potentially unlock latent demand that has otherwise been priced out since the disruption of Russian natural gas supply to Europe.

The increase in supply corresponded to a 5% YoY uptick in trade, which was primarily supported by Europe and the Middle East and North Africa (“MENA”) region amid weaker demand in Asia. Europe’s demand for LNG increased approximately 27% YoY in 2025 reaching a record level of approximately 125 mtpa. The main driver for this growth continues to be the replacement of Russian natural gas and the replenishment of underground storage inventories. We expect this driver to continue to play an important role in keeping LNG demand in Europe resilient, especially in light of the European Parliament’s vote to ban all residual Russian natural gas, including Russian LNG by 2027. The MENA region also contributed to demand growth in 2025 with imports increasing 7 mtpa or 62% versus 2024. Egypt was the main driver of this increase as it resorted to additional LNG imports to satisfy its growing domestic energy needs and supplement its own natural gas production.

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Asia’s LNG consumption however was down about 4% in 2025, dropping by 12 mtpa to 270 mtpa. While many of the major markets in Asia saw YoY declines, China’s was the largest, representing nearly the entire YoY change in the region. China’s LNG imports declined 16% or 12 mtpa YoY, due to broader, likely transient macro-economic challenges. Natural gas demand growth in China slowed in 2025 and higher piped natural gas flows from Russia and robust domestic natural gas production decreased the call on LNG.

Despite weaker demand in Asia and an easing in geopolitical conflicts during the second half of 2025, average prices remained elevated versus 2024. The Japan Korea Marker (“JKM”) monthly settlement prices in 2025 averaged $12.71 per MMBtu, 7.5% higher YoY while those for Title Transfer Facilities (“TTF”) averaged $12.04 per MMBtu, 10.3% higher YoY. Strong storage injections, an increase in LNG supply and expectations of mild weather resulted in downward pressure in the second half of the year with monthly settlements averaging at least $1.76 per MMBtu lower for JKM and $2.34 per MMBtu lower for TTF versus the first half of the year. Henry Hub monthly settlements averaged $3.43 per MMBtu during 2025.

As referenced above, expectations of significant LNG capacity expansions in the next few years, and the recent momentum in FIDs if continued, are likely to keep the price trajectory trending lower in Asia and Europe. We expect the price elastic markets, particularly in Asia, to respond to the increased availability and affordability of supply by growing imports to satisfy latent demand as well as organic longer-term growth.
Results of Operations

Consolidated results of operations

Year Ended December 31,
(in millions, except per share data)20252024Variance
Revenues
LNG revenues$19,435 $14,899 $4,536 
Regasification revenues136 135 1 
Other revenues405 669 (264)
Total revenues19,976 15,703 4,273 
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below)7,150 6,021 1,129 
Operating and maintenance expense1,966 1,857 109 
Selling, general and administrative expense383 441 (58)
Depreciation, amortization and accretion expense1,329 1,220 109 
Other operating costs and expenses36 36 — 
Total operating costs and expenses10,864 9,575 1,289 
Income from operations9,112 6,128 2,984 
Other income (expense)
Interest expense, net of capitalized interest(948)(1,010)62 
Gain (loss) on modification or extinguishment of debt(8)(9)1 
Interest and dividend income106 189 (83)
Other income, net20 5 15 
Total other expense(830)(825)(5)
Income before income taxes and NCI
8,282 5,303 2,979 
Less: income tax provision1,488 811 677 
Net income6,794 4,492 2,302 
Less: net income attributable to NCI1,464 1,240 224 
Net income attributable to Cheniere$5,330 $3,252 $2,078 
Net income per share attributable to common stockholders—basic
$24.19 $14.24 $9.95 
Net income per share attributable to common stockholders—diluted
$24.13 $14.20 $9.93 
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Volumes loaded and recognized from the Liquefaction Projects
Year Ended December 31,
20252024
(in TBtu)OperationalCommissioningTotalOperationalCommissioningTotal
Volumes loaded during the current period2,400 24 2,424 2,327 — 2,327 
Volumes loaded during the prior period but recognized during the current period39 — 39 37 — 37 
Less: volumes loaded during the current period and in transit at the end of the period(23)(1)(24)(39)— (39)
Total volumes recognized in the current period2,416 23 2,439 2,325 — 2,325 

Components of LNG revenues and corresponding LNG volumes delivered
Year Ended December 31,
 20252024Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)
$14,804 $12,144 $2,660 
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2)
3,794 2,345 1,449 
LNG procured from third parties (2)226 280 (54)
Net derivative gain (loss)
344 (73)417 
Other revenues267 203 64 
Total LNG revenues$19,435 $14,899 $4,536 
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)
2,095 2,118 (23)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements (2)
321 207 114 
LNG procured from third parties (2)22 24 (2)
Total volumes delivered as LNG revenues2,438 2,349 89 
(1)Long-term agreements include agreements with an initial tenor of 12 months or more.
(2)Includes volumes sold under short-term agreements and volumes sold from natural gas procured under IPM agreements.

2025 vs. 2024

Net income attributable to Cheniere increased by $2.1 billion during the year ended December 31, 2025 as compared to the same period of 2024 primarily due to $2.3 billion of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our derivatives related to IPM agreements, and an $876 million increase in revenues, net of cost of natural gas feedstock, from increased volume of LNG loaded and recognized between the years. Partially offsetting these favorable changes was an increased tax provision of $677 million. The following is an expanded discussion of the significant drivers of the variance in net income attributable to Cheniere by line item:
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Total revenues

The $4.3 billion increase in total revenues during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to:
•$2.9 billion increase due to higher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;
•$1.2 billion increase due to higher volumes of LNG delivered between the periods, primarily as a result of increased production volume due to the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025;
•$417 million increase in gains from agreements accounted for as derivative instruments included in revenues, largely due to the impact of declines in global gas prices and volatility within our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG, of which the gain between the years was attributable to a $223 million gain from favorable changes in fair value of agreements accounted for as derivatives and a $194 million gain from the settlement of previously entered derivative instruments; partially offset by
•$243 million decrease in sublease and subcharter income from our LNG vessels due to fewer days the LNG vessels were subcontracted out and at lower rates in the current year as compared to the same period of 2024.

Total operating costs and expenses

The $1.3 billion increase in total operating costs and expenses during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to:
•$3.1 billion increase in the cost of natural gas feedstock, largely due to the increase in U.S. natural gas prices and to a lesser degree, increased volume of LNG delivered;
•$109 million increase in depreciation, amortization and accretion expense, primarily as a result of the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project;
•$109 million increase in operating and maintenance expense primarily due to the completion of planned large-scale maintenance activities on two Trains at the SPL Project and additional expenses from the substantial completions of the first four Trains of the Corpus Christi Stage 3 Project in 2025; partially offset by:
•$2.1 billion of gains from changes in fair value of agreements accounted for as derivative instruments included in cost of sales, largely due to favorable changes on our IPM agreements from the narrowing of global and U.S. domestic natural gas spreads, the effect of which is minimized by the relative change in volatilities of applicable global and U.S. domestic natural gas prices, partially offset by changes in market-based locational forward price differentials for North American natural gas deliveries.

As further discussed in Liquidity and Capital Resources, we will recognize a $370 million reduction to cost of sales due to the realization of certain excise tax credits during the three months ending March 31, 2026.

Total other expense

The $5 million increase in total other expense during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to:
•$83 million decrease in interest and dividend income as a result of decreased interest rates and lower average cash and cash equivalents balances between the periods; partially offset by
•$62 million decrease in interest expense, net of capitalized interest, due to a $33 million increase in capitalized interest costs given the higher carrying value of assets under construction and additionally due to $29 million lower gross interest costs due to debt reduction activities associated with our long-term capital allocation plan; and
•$15 million increase in other income, net, primarily from a $26 million gain recognized on the sale of our equity interests in an equity method investment during the three months ended March 31, 2025.

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Income tax provision

The $677 million unfavorable variance during the year ended December 31, 2025 as compared to the same period of 2024 was substantially all attributable to a higher income tax expense due to a $3.0 billion increase in pre-tax income. The effect of the change in our effective tax rate between the comparable periods was not material to our income tax provision.

On July 4, 2025, the OBBBA was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting Foreign Derived Intangible Income (“FDII”) deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.

The legislation did not have a material impact on our income tax expense for the year ended December 31, 2025, and it did not materially change our effective income tax rate for 2025; however, commencing with its effectiveness in 2026, we expect that the FDDEI regime will favorably impact our effective tax rate relative to prior policy, as a larger portion of our export-related income is projected to be eligible for a preferential tax rate despite an increase in the tax rate on qualifying sales. The FDDEI regime provides for an effective tax rate of 14%, a rate lower than the statutory corporate tax rate of 21%, on eligible sales of property or services to a foreign person for foreign use. Relative to the prior FDII tax rules, the FDDEI regime increases the effective tax rate on eligible sales but broadens qualifying income by eliminating certain asset-based eligibility constraints and removing the requirement to reduce eligible income by specified allocable expenses.

See Liquidity and Capital Resources for discussion of the impacts of the OBBBA on our liquidity.

Net income attributable to NCI

The $224 million increase during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to a $477 million increase in CQP’s consolidated net income primarily from favorable changes in fair value of agreements accounted for as derivative instruments.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. For commodity derivative instruments, including those related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

Commissioning volumes

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for
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the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the year ended December 31, 2025, we realized offsets to LNG terminal costs of $187 million corresponding to 23 TBtu of LNG that was related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project. We did not record any offsets to LNG terminal costs during the year ended December 31, 2024.

Additional liquefaction capacities

The Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project are currently under construction and are expected to add over 15 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion, of which over 9 mtpa is still under construction as of December 31, 2025. As of December 31, 2025, the first four Trains of the Corpus Christi Stage 3 Project were in operation, with substantial completions for each Train achieved in March, August, October and December 2025, respectively. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. However, prior to the commencement of long-term SPAs associated with these volumes, the additional volumes will be sold by our integrated marketing function at prevailing market prices. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed in Items 1. and 2. Business and Properties, would also be expected to result in higher revenues and operating costs and expenses.

Additionally, see Items 1. and 2. Business and Properties for discussion of our business seasonality.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries.

The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
December 31, 2025
Cash and cash equivalents (1)$1,099 
Restricted cash and cash equivalents (1)485 
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility
824 
CQP Revolving Credit Facility
1,000 
CCH Credit Facility
2,710 
CCH Working Capital Facility
1,390 
Cheniere Revolving Credit Facility
1,250 
Total available commitments under our credit facilities7,174 
Total available liquidity$8,758 
(1)Amounts presented include balances held by our VIEs, as discussed in Note 8—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of December 31, 2025, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $182 million of cash and cash equivalents and $22 million of restricted cash and cash equivalents.
(2)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of December 31, 2025. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to December 31, 2025 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity.

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Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions or requirements under debt and equity instruments executed by our subsidiaries limit the entity’s use of cash, including the following:
•SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;
•CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;
•Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and
•SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on these covenants.

Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

Future Sources and Uses of Liquidity

The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2025. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.
Future Sources of Liquidity under Executed Contracts

We expect future material sources of liquidity to be derived from our long-term customer arrangements and structured cash flows under our SPAs and IPM agreements. As described in Items 1. and 2. Business and Properties, these contracts with creditworthy counterparties form the foundation of our business and provide us with significant, stable, long-term cash flows. Under our long-term SPAs and IPM agreements, as of December 31, 2025, we have contracted approximately 90% of the total anticipated production from the Liquefaction Projects through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us.

LNG Revenues from Executed SPAs

We are contractually entitled to significant future consideration contracted under our long-term SPAs that has not yet been recognized as revenue. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be significant to our future liquidity. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with
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terms dependent on project milestone dates based on the estimated dates as of December 31, 2025. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2025 (in billions):
 
Estimated Revenues Under Executed SPAs by Period (1) (2)
 2026
2027 - 2030
ThereafterTotal
LNG revenues (fixed fees)$6.6 $29.4 $71.7 $107.7 
LNG revenues (variable fees) (3)9.8 43.9 129.2 182.9 
Total$16.4 $73.3 $200.9 $290.6 
(1)LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones, such as reaching FID on a certain liquefaction Train.
(2)LNG revenues exclude revenues from contracts with original expected durations of one year or less.
(3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2025.

As described in General, under our SPAs, customers purchase LNG on either an FOB basis or a DAP basis generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The variable fees under our SPAs were generally sized with the intention to cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension.

LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements. The LNG produced and available for Cheniere Marketing to sell includes volumes related to commissioning, which are not recognized as revenues. We recognize proceeds from commissioning activities prior to the start of commercial operations as offsets to LNG terminal costs, as a component of the testing phase of a Train’s construction. The volumes sold by Cheniere Marketing may be supplemented by volumes procured from third parties at other locations worldwide to support operational requirements or take advantage of market opportunities.

Liquidity from Executed IPM Agreements

The table in the LNG Revenues from Executed SPAs section above excludes fees expected to be generated through sales of LNG produced from natural gas procured under our IPM agreements, under which we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure under the IPM agreements generates a take-or-pay style fixed liquefaction fee. Although the IPM agreements secure natural gas purchases over long-term periods, the LNG produced from that natural gas is generally sold under short-term SPAs. Over a remaining fixed term of 20 years, we expect to generate liquidity from the approximately 5,066 TBtu of LNG to be produced from natural gas not yet received under IPM agreements as of December 31, 2025.

Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2025, we had $7.2 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2027 and 2030, based on estimated project milestone dates as of December 31, 2025.

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Disciplined Accretive Growth

Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities. Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate the CCL Expansion Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2025 (in billions):
Estimated Payments Due Under Executed Contracts by Period (1)
2026
2027 - 2030
ThereafterTotal
Purchase obligations (2):
Natural gas supply agreements excluding IPM agreements (3) (4)
$7.3 $13.3 $5.0 $25.6 
Natural gas transportation and storage service agreements (5)0.6 2.2 4.4 7.2 
Capital expenditures1.5 0.9 — 2.4 
Other Purchase Obligations— 0.1 0.5 0.6 
Leases (6)0.9 3.2 4.7 8.8 
Total$10.3 $19.7 $14.6 $44.6 
(1)Agreements in force as of December 31, 2025 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2025.
(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.
(3)Natural gas supply agreements exclude IPM agreements, which are structured to generate a fixed margin when viewed in conjunction with the sale of LNG produced from the natural gas procured under the IPM agreements, as described under Liquidity from Executed IPM Agreements.
(4)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2025. Natural gas supply agreements are presented net of $0.2 billion in contracted sales of natural gas as of December 31, 2025.
(5)Natural gas transportation and storage services agreements include $1.3 billion in obligations to related parties. See Note 13 — Related Party Transactions for further information about our related parties.
(6)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2025 but will commence in the future. Payments during future renewal option periods that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised. Leases are presented net of future income associated with vessel time charters that were subchartered to third parties, which was immaterial as of December 31, 2025.

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Natural Gas Supply, Transportation and Storage Service Agreements

Excluding IPM agreements and unexercised extension options, we have secured approximately 6,847 TBtu of natural gas feedstock for our Liquefaction Projects through long-term natural gas supply agreements with remaining fixed terms of up to 14 years. As of December 31, 2025, we have secured approximately 70% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2026, excluding the 8% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2026. As further described in LNG Revenues from Executed SPAs, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, thus limiting our net exposure to future increases in natural gas prices.

To ensure that we are able to transport natural gas feedstock to the Liquefaction Projects, we have transportation precedent and other agreements to secure firm pipeline transportation capacity from interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Projects.

Capital Expenditures

We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Projects. The future capital expenditures included in the table above primarily consist of fixed costs under the lump sum Bechtel EPC contracts for both the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. As of December 31, 2025, substantial completions of the first four of seven midscale Trains of the Corpus Christi Stage 3 Project were achieved. Additionally, in June 2025, our Board made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under an EPC contract for a contract price of approximately $2.9 billion, subject to adjustment only by change order. Refer to Corpus Christi LNG Terminal in Items 1. and 2. Business and Properties — Our Business for a summary of the construction status and estimated completion of both the Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project as of December 31, 2025. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity.

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with fixed minimum terms of up to 15 years to ensure delivery of cargoes sold on a DAP basis. We have also entered into leases for the use of tug vessels, office space and facilities, land sites and equipment.

Additional Future Cash Requirements for Operations and Capital Expenditures

Taxes

Our cash tax payments may fluctuate over time and may be influenced by (1) accelerated tax depreciation deductions on qualifying assets, including the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project and (2) timing of utilization of our existing net operating loss (“NOL”) carryforwards. See the risk Additions or changes in tax laws and regulations or variables impacting our tax obligations could potentially affect our financial results or liquidity under Risks Relating to Regulations in Item 1A. Risk Factors.

As part of our ongoing effort to mitigate our emissions from our shipping transport operations, we primarily utilize the LNG that we produce at our terminals as transport fuel in our shipping vessel operations, serving as a substitute for diesel and heavy fuel oils, which have higher emission factors. Our use of LNG as transport fuel in our operations enabled us to claim federal alternative fuel excise tax credits totaling $370 million for the period spanning from 2018 to 2024, preceding the expiration of the incentive program on December 31, 2024. We accounted for the claims as a gain contingency under ASC 450-30, Contingencies - Gain Contingencies, which does not allow recognition until cash or claims to cash are realized or realizable. We did not recognize the claims as of December 31, 2025 because there were inherent uncertainties associated with the realizability of these claims. Subsequent to December 31, 2025, the Internal Revenue Service (the “IRS”) issued a closing
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letter to us indicating completion of their review, confirming our eligibility and issuing final cash payment. As such, we will recognize a $370 million reduction to cost of sales during the three months ending March 31, 2026.

Disciplined Accretive Growth

The FID of any expansion projects, including the SPL Expansion Project and CCL Expansion Project, will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

In January 2026, we acquired the remaining redeemable noncontrolling interest in our consolidated subsidiary that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located immediately proximal to the Corpus Christi LNG Terminal. Such acquisition enhances operational control and further mitigates risk exposure associated with increased power demand from the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, but is expected to require further capital injection for operating liquidity and capital improvements.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2025 (in billions):
 Estimated Payments Due Under Executed Contracts by Period (1) (2)
 2026
2027 - 2030
ThereafterTotal
Debt$0.3 $11.8 $10.9 $23.0 
Interest payments1.1 3.2 1.7 6.0 
Total$1.4 $15.0 $12.6 $29.0 
(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2025. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.
(2)Table excludes payments under finance leases, which are included in Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts table above.

Debt

As of December 31, 2025, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $22.4 billion and credit facilities with $550 million outstanding loan balances. As of December 31, 2025, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2025, our senior notes had a weighted average contractual interest rate of 4.65%. Interest on borrowings under our credit facilities is indexed to SOFR, and we are subject to interest rates on outstanding balances, commitment fees on undrawn balances and letter of credit fees on issued letters of credit. We had $286 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2025. Further details of our credit facilities can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.
Additional Future Cash Requirements for Financing

CQP Distributions

CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner. We own a 48.6% limited
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partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2025, $803 million in distributions were paid to our non-controlling interests.

Capital Allocation Plan

In June 2024, our Board approved an updated comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027. As of December 31, 2025, we had up to $1.2 billion available under the share repurchase program. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors, with the majority of the repurchases executed within trading parameters pre-established for each applicable trading period in compliance with SEC Rule 10b5-1 and some repurchases executed on the open market. During the year ended December 31, 2025, we repurchased approximately 12.1 million shares of our common stock for $2.7 billion at a weighted average price per share of $221.55. A discussion of our share repurchase program can be found in Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of Equity Securities.

Another aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2025, we used $0.7 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.

In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share, which commenced with the dividend pertaining to the third quarter of 2025. On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.

Financially Disciplined Growth

To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the SPL Expansion Project and the CCL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table. 
Year Ended December 31,
20252024
Net cash provided by operating activities$5,539 $5,394 
Net cash used in investing activities(3,012)(2,279)
Net cash used in financing activities(4,130)(4,451)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents(3)1 
Net decrease in cash, cash equivalents and restricted cash and cash equivalents
$(1,606)$(1,335)
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Operating Cash Flows

The $145 million increase between the periods was primarily related to higher net cash inflows from LNG sales, as explained above in Results of Operations, and increased cash inflows from settlement of derivative instruments. Partially offsetting the increase was lower cash flows attributed to working capital from differences in timing of cash collections from the sale of LNG cargoes and payments to suppliers.

As described in Results of Operations, the OBBBA was signed into law during the third quarter of 2025 and includes, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025, which deferred our cash tax obligations, ultimately reducing our income tax payable to a nominal amount in 2025, and modifying the export-promoting FDII deduction rules, renamed to the FDDEI under the OBBBA, which is expected to reduce our income taxes payable relative to prior policy in future periods. Additionally, on September 30, 2025, the IRS issued Notice 2025-49, which revised rules for calculating CAMT adjusted financial statement income, deferring our cash tax obligations and entitling us to a refund of $380 million of previously paid CAMT, which we received in December 2025.
Investing Cash Flows

Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.3 billion and $1.5 billion during the years ended December 31, 2025 and 2024, respectively; (2) $1.0 billion of costs paid for the CCL Midscale Trains 8 & 9 Project during the year ended December 31, 2025, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods. The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to a decline in expenditures in the current year related to the EPC contract as the project approaches completion. We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as construction progresses on these projects.

Financing Cash Flows

The following table summarizes our financing activities (in millions):
Year Ended December 31,
20252024
Proceeds from issuances of debt and borrowings$1,987 $2,725 
Redemptions and repayments of debt(2,092)(3,521)
Distributions to NCI
(803)(846)
Contributions from redeemable NCI
122 6 
Payments related to tax withholdings for share-based compensation(51)(46)
Repurchase of common stock, inclusive of excise taxes paid(2,724)(2,262)
Dividends to stockholders(451)(412)
Other, net(118)(95)
Net cash used in financing activities$(4,130)$(4,451)

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Proceeds from Issuances of Debt and Borrowings

The following table shows the proceeds from issuances of debt and borrowings, including intra-year activity (in millions):
Year Ended December 31,
20252024
Cheniere:
5.650% Senior Notes due 2034
$— $1,497 
Cheniere Revolving Credit Facility175 — 
CQP:
5.750% Senior Notes due 2034
— 1,198 
2035 CQP Senior Notes997 — 
SPL:
SPL Revolving Credit Facility265 30 
CCH:
CCH Credit Facility550 — 
Total proceeds from issuances of debt and borrowings$1,987 $2,725 

Debt Redemptions and Repayments

The following table shows the redemptions and repayments of debt, including intra-year activity (in millions):
Year Ended December 31,
20252024
Cheniere:
Cheniere Revolving Credit Facility$(175)$— 
SPL:
5.750% Senior Secured Notes due 2024
— (300)
2025 SPL Senior Notes(300)(1,700)
2026 SPL Senior Notes(1,300)— 
4.746% weighted average rate Senior Notes due 2037
(52)— 
SPL Revolving Credit Facility(265)(30)
CCH:
5.875% Senior Notes due 2025
— (1,491)
Total redemptions and repayments of debt$(2,092)$(3,521)

Repurchase of Common Stock

During the years ended December 31, 2025 and 2024, we paid $2.7 billion and $2.3 billion to repurchase approximately 12.1 million and 13.8 million shares of our common stock, respectively, under our share repurchase program. Additionally, during the year ended December 31, 2025, we paid $33 million of excise taxes related to our repurchase of common stock during the fiscal years 2023 and 2024, since the IRS imposes an excise tax of 1% on the fair market value of our stock repurchases less our stock issuances. In April 2026, we expect to pay $26 million of excise taxes related to our repurchases during the fiscal year 2025. As of December 31, 2025, we had approximately $1.2 billion remaining under our share repurchase program. In February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization.
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Cash Dividends to Stockholders

During the year ended December 31, 2025, we paid aggregate dividends of $2.055 per share of common stock for a total of $451 million and during the year ended December 31, 2024, we paid aggregate dividends of $1.805 per share of common stock for a total of $412 million.

On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.
Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value of Level 3 Liquefaction Supply Derivatives

Our derivative instruments are recorded at fair value unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.
Our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

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Additionally, the valuation of certain liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of liquefaction supply derivatives valued through the use of internal models which incorporate significant unobservable inputs for the years ended December 31, 2025 and 2024 (in millions). The changes in fair value shown are limited to instruments still held at the end of each respective period.
Year Ended December 31,
20252024
Favorable changes in fair value of liquefaction supply derivatives still held at the end of the period
$2,887 $738 

The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements in effect during the years ended December 31, 2025 and 2024.
The estimated fair value of level 3 liquefaction supply derivatives recognized in our Consolidated Balance Sheets as of December 31, 2025 and 2024 amounted to an asset of $2.9 billion and a liability of $801 million, respectively.

The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices impacting the valuation of our liquefaction supply derivatives, given the level of volatility to which such prices are subjected. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.
Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Marketing and Trading Commodity Price Risk

We have commodity derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Projects and the SPL Expansion Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”) and LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):
December 31, 2025December 31, 2024
Fair Value Change in Fair ValueFair Value Change in Fair Value
Liquefaction Supply Derivatives$2,865 $2,722 $(742)$2,516 
LNG Trading Derivatives(17)1 17 49 

See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES


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MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
 
Management’s Report on Internal Control Over Financial Reporting
 
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
 
Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2025, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.

Cheniere’s independent registered public accounting firm, KPMG LLP, has issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2025, which is contained in this Form 10-K.
 
Management’s Certifications
 
The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.
 
CHENIERE ENERGY, INC.
     
By:/s/ Jack A. Fusco By:/s/ Zach Davis
Jack A. FuscoZach Davis
 President and Chief Executive Officer
(Principal Executive Officer)		  Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors
Cheniere Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders’ equity (deficit) and redeemable non-controlling interest, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fair value of the level 3 liquefaction supply derivatives
As discussed in Notes 2 and 6 to the consolidated financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $2,902 million as of December 31, 2025, which included the fair value of IPM agreements. The IPM agreements are natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the IPM agreements is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.
We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for the IPM agreements as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.

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The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of liquefaction supply derivatives, including those under certain IPM agreements. This included controls related to the appropriateness and application of the option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of certain IPM agreements by:
•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model
•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use
•evaluating the reasonableness of management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.


/s/    KPMG LLP
KPMG LLP
 



We have served as the Company’s auditor since 2014.

Houston, Texas
February 25, 2026

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors
Cheniere Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Cheniere Energy, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders’ equity (deficit) and redeemable non-controlling interest, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2026 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/    KPMG LLP
KPMG LLP
 
Houston, Texas
February 25, 2026

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CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)

Year Ended December 31,
202520242023
Revenues
LNG revenues$19,435 $14,899 $19,569 
Regasification revenues136 135 135 
Other revenues405 669 690 
Total revenues19,976 15,703 20,394 
Operating costs and expenses
Cost of sales (excluding operating and maintenance expense and depreciation, amortization and accretion expense shown separately below)7,150 6,021 1,356 
Operating and maintenance expense1,966 1,857 1,835 
Selling, general and administrative expense383 441 474 
Depreciation, amortization and accretion expense1,329 1,220 1,196 
Other operating costs and expenses36 36 44 
Total operating costs and expenses10,864 9,575 4,905 
Income from operations9,112 6,128 15,489 
Other income (expense)
Interest expense, net of capitalized interest(948)(1,010)(1,141)
Gain (loss) on modification or extinguishment of debt(8)(9)15 
Interest and dividend income106 189 211 
Other income, net20 5 4 
Total other expense(830)(825)(911)
Income before income taxes and NCI
8,282 5,303 14,578 
Less: income tax provision1,488 811 2,519 
Net income6,794 4,492 12,059 
Less: net income attributable to NCI1,464 1,240 2,178 
Net income attributable to Cheniere$5,330 $3,252 $9,881 
Net income per share attributable to common stockholders—basic (1)
$24.19 $14.24 $40.99 
Net income per share attributable to common stockholders—diluted (1)
$24.13 $14.20 $40.72 
Weighted average number of common shares outstanding—basic219.7 228.4 241.0 
Weighted average number of common shares outstanding—diluted220.3 229.1 242.6 
___________________
(1)In computing basic and diluted net income per share attributable to common stockholders, net income attributable to Cheniere is adjusted for the remeasurement of the redeemable NCI, net of tax, to its redemption value, as required under the two-class method. See Note 17—Net Income per Share Attributable to Common Stockholders for the full computation.
The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (1)
(in millions, except share data)
December 31,
20252024
ASSETS
Current assets  
Cash and cash equivalents$1,099 $2,638 
Restricted cash and cash equivalents485 552 
Trade and other receivables, net of current expected credit losses1,380 727 
Inventory524 501 
Current derivative assets9 155 
Margin deposits76 128 
Other current assets, net119 100 
Total current assets3,692 4,801 
Property, plant and equipment, net of accumulated depreciation35,755 33,552 
Operating lease assets2,700 2,684 
Derivative assets4,663 1,903 
Deferred tax assets12 19 
Other non-current assets, net1,060 899 
Total assets$47,882 $43,858 
LIABILITIES, REDEEMABLE NCI AND STOCKHOLDERS’ EQUITY
Current liabilities 
Accounts payable$123 $171 
Accrued liabilities2,081 2,179 
Current debt, net of unamortized discount and debt issuance costs306 351 
Deferred revenue150 163 
Current operating lease liabilities539 592 
Current derivative liabilities618 902 
Other current liabilities99 83 
Total current liabilities3,916 4,441 
Long-term debt, net of unamortized discount and debt issuance costs22,507 22,554 
Operating lease liabilities2,163 2,090 
Derivative liabilities1,208 1,865 
Deferred tax liabilities3,698 1,856 
Other non-current liabilities1,312 992 
Total liabilities34,804 33,798 
Commitments and contingencies (see Note 19)
Redeemable NCI136 7 
Stockholders’ equity 
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued
— — 
Common stock: $0.003 par value, 480.0 million shares authorized; 279.2 million shares and 278.7 million shares issued at December 31, 2025 and 2024, respectively
1 1 
Treasury stock: 66.8 million shares and 54.7 million shares at December 31, 2025 and 2024, respectively, at cost
(8,852)(6,136)
Additional paid-in-capital4,523 4,452 
Retained earnings
12,243 7,382 
Total Cheniere stockholders’ equity
7,915 5,699 
NCI5,027 4,354 
Total stockholders’ equity12,942 10,053 
Total liabilities, redeemable NCI and stockholders’ equity
$47,882 $43,858 
(1)Amounts presented include balances held by our consolidated variable interest entities (“VIEs”), substantially all of which are related to CQP. As of December 31, 2025, total assets and liabilities of our VIEs were $17.3 billion and $17.0 billion, respectively, as further detailed in Note 8—Non-Controlling Interests and Variable Interest Entities, including $182 million of cash and cash equivalents and $22 million of restricted cash and cash equivalents.
The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) AND REDEEMABLE NON-CONTROLLING INTEREST
(in millions)
Total Stockholders’ Equity (Deficit)
 Common StockTreasury StockAdditional Paid-in CapitalRetained Earnings
NCI
Total Equity (Deficit)
Redeemable NCI (1)
 SharesPar Value AmountSharesAmount
Balance at December 31, 2022245.5 $1 31.2 $(2,342)$4,314 $(4,942)$2,798 $(171)$— 
Net income— — — — — 9,881 2,178 12,059 — 
Dividends declared ($1.62 per common share) and dividend equivalents accrued
— — — — — (393)— (393)— 
Shares repurchased, at cost and inclusive of excise taxes(9.5)— 9.5 (1,496)— — — (1,496)— 
Distributions to NCI
— — — — — — (1,016)(1,016)— 
Vesting of share-based compensation awards1.2 — — — — — — — — 
Share-based compensation— — — — 100 — — 100 — 
Issued shares withheld from employees related to share-based compensation, at cost(0.2)— 0.2 (26)(37)— — (63)— 
Balance at December 31, 2023237.0 1 40.9 (3,864)4,377 4,546 3,960 9,020 — 
Net income— — — — — 3,252 1,240 4,492 — 
Dividends declared ($1.805 per common share) and dividend equivalents accrued
— — — — — (415)— (415)— 
Shares repurchased, at cost and inclusive of excise taxes(13.8)— 13.8 (2,272)— — — (2,272)— 
Accretion of redeemable NCI (2)
— — — — — (1)— (1)1 
Distributions to NCI
— — — — — — (846)(846)— 
Contributions from redeemable NCI
— — — — — — — — 6 
Vesting of share-based compensation awards0.8 — — — — — — — — 
Share-based compensation— — — — 121 — — 121 — 
Issued shares withheld from employees related to share-based compensation, at cost— — — — (46)— — (46)— 
Balance at December 31, 2024224.0 1 54.7 (6,136)4,452 7,382 4,354 10,053 7 
Net income (loss)— — — — — 5,330 1,476 6,806 (12)
Dividends declared ($2.055 per common share) and dividend equivalents accrued
— — — — — (454)— (454)— 
Shares repurchased, at cost and inclusive of excise taxes(12.1)— 12.1 (2,716)— — — (2,716)— 
Accretion of redeemable NCI (2)
— — — — — (15)— (15)19 
Distributions to NCI
— — — — — — (803)(803)— 
Contributions from redeemable NCI
— — — — — — — — 122 
Vesting of share-based compensation awards0.5 — — — — — — — — 
Share-based compensation— — — — 122 — — 122 — 
Issued shares withheld from employees related to share-based compensation, at cost— — — — (51)— — (51)— 
Balance at December 31, 2025212.4 $1 66.8 $(8,852)$4,523 $12,243 $5,027 $12,942 $136 
(1)Redeemable NCI represents the economic interest held by a third party in one of our consolidated VIEs that is redeemable for cash under certain circumstances, including those that are outside of our control. As such, the economic interest is not a component of permanent equity on our Consolidated Balance Sheets. In January 2026, we redeemed the remaining redeemable NCI in our consolidated VIE that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located immediately proximal to the Corpus Christi LNG Terminal, at a price that approximated our carrying value.
(2)Amount in retained earnings presented net of tax.
The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

Year Ended December 31,
202520242023
Cash flows from operating activities
Net income
$6,794 $4,492 $12,059 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion expense1,329 1,220 1,196 
Share-based compensation expense161 215 250 
Amortization of discount and debt issuance costs38 42 44 
Reduction of right-of-use assets623 670 623 
Total gains on derivative instruments, net
(3,844)(1,315)(7,890)
Net cash provided by (used for) settlement of derivative instruments
289 (100)(79)
Deferred taxes1,859 330 2,389 
Other, net25 28 3 
Changes in operating assets and liabilities:
Trade and other receivables(640)380 840 
Inventory(32)(57)377 
Margin deposits52 (111)116 
Other non-current assets(156)(80)(64)
Accounts payable and accrued liabilities(232)248 (982)
Total deferred revenue(41)(2)3 
Total operating lease liabilities(619)(658)(607)
Other, net(67)92 140 
Net cash provided by operating activities
5,539 5,394 8,418 
Cash flows from investing activities
Property, plant and equipment, net of proceeds from commissioning sales of LNG of $174 million, zero and zero, respectively
(3,078)(2,238)(2,121)
Investments in equity method investments(2)(12)(61)
Other, net68 (29)(20)
Net cash used in investing activities
(3,012)(2,279)(2,202)
Cash flows from financing activities
Proceeds from issuances of debt and borrowings1,987 2,725 1,397 
Redemptions and repayments of debt(2,092)(3,521)(2,598)
Distributions to NCI
(803)(846)(1,016)
Contributions from redeemable NCI
122 6 — 
Payments related to tax withholdings for share-based compensation(51)(46)(63)
Repurchase of common stock, inclusive of excise taxes paid(2,724)(2,262)(1,473)
Dividends to stockholders(451)(412)(393)
Other, net(118)(95)(34)
Net cash used in financing activities
(4,130)(4,451)(4,180)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents(3)1 2 
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents
(1,606)(1,335)2,038 
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period3,190 4,525 2,487 
Cash, cash equivalents and restricted cash and cash equivalents—end of period$1,584 $3,190 $4,525 



The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We operate natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”), with total expected production capacity of over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 9 mtpa was under construction and the remainder was in operation as of December 31, 2025, comprised of the following:
•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities at the Sabine Pass LNG Terminal owned by CQP (the “SPL Project”). The Sabine Pass LNG Terminal also has five LNG storage tanks, vaporizers and three marine berths. CQP also owns and operates a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”). As of December 31, 2025, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.
•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 9 mtpa under construction and the remainder in operation as of December 31, 2025, from our natural gas liquefaction facilities at the Corpus Christi LNG Terminal, of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks and two marine berths. We also own an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). The projects under construction at the Corpus Christi LNG Terminal include:
◦a project consisting of seven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the “Corpus Christi Stage 3 Project”), with over 4 mtpa under construction and the remainder in operation from the first four midscale Trains that have reached substantial completion as of December 31, 2025; and
◦a project consisting of two additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the “CCL Project”), which was under construction as of December 31, 2025. Our board of directors (our “Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025.
In addition to the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”), we are developing expansion projects to provide additional liquefaction capacity at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal and are commercializing to support the additional liquefaction capacity associated with these potential expansion projects. These projects or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before our Board makes a positive FID.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Cheniere, its subsidiaries in which we hold a controlling interest and VIEs we consolidate under certain criteria discussed further below. All intercompany accounts and transactions have been eliminated in consolidation.

VIEs

We make a determination at the inception of each arrangement whether an entity in which we have made an investment or in which we have other variable interests is considered a VIE. Generally, an entity is a VIE if either (1) the entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, (2) the entity’s investors lack any characteristics of a controlling financial interest or (3) the entity was established with non-substantive voting rights.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We consolidate VIEs when we are deemed to be the primary beneficiary. The primary beneficiary of a VIE is generally the party that both: (1) has the power to make decisions that most significantly affect the economic performance of the VIE and (2) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. If we are not deemed to be the primary beneficiary of a VIE, we account for the investment or other variable interests in a VIE in accordance with applicable GAAP.
See Note 8—Non-controlling Interests and Variable Interest Entities for additional details about our assessment of VIEs.
Non-controlling Interests

When we consolidate an entity, we include 100% of the assets, liabilities, revenues and expenses of the entity in our Consolidated Financial Statements. For those entities that we consolidate in which our ownership is less than 100%, we record a non-controlling interest as a component of equity on our Consolidated Balance Sheets, which represents the third party ownership in the net assets of the respective consolidated subsidiary. Changes in our ownership interests in an entity that do not result in deconsolidation are generally recognized within equity.

Non-controlling interests are presented in permanent equity within our Consolidated Balance Sheets unless they are redeemable at a fixed or determinable price on a fixed or determinable date at the option of the holder or upon the occurrence of an event that is not solely within our control, in which case they are presented in temporary equity. The carrying amount of the redeemable non-controlling interest is equal to the greater of (1) the carrying value of the non-controlling interest adjusted each reporting period for income or loss attributable to the non-controlling interest as well as any applicable distributions made or (2) the redemption value. Remeasurements to the redemption value of the redeemable non-controlling interest are recognized in retained earnings within the Consolidated Balance Sheets.

The portion of the net income or loss attributable to the non-controlling interests and redeemable non-controlling interest is reported as net income or loss attributable to non-controlling interests on our Consolidated Statements of Operations. See Note 8—Non-controlling Interests and Variable Interest Entities for additional details about our non-controlling interests.

Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment, leases, asset retirement obligations (“AROs”) and recoverability of deferred tax assets, each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data, or models that incorporate observable market data, when such data is available. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We attempt to maximize our use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 6—Derivative Instruments, and liability-classified share-based compensation awards, as disclosed in Note 15—Share-Based Compensation.

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The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 10—Debt for our debt fair value estimates, including our estimation methods.
Revenue Recognition

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the FOB or DAP delivery terms, which is generally the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer.

Sales generated during the commissioning phase of a Train are offset against the cost of construction for the respective Train, as further described under the caption Property, Plant and Equipment below. After substantial completion of a Train is achieved, fees received for LNG volumes produced are recognized as LNG revenues.

With respect to regasification revenues, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the variable fees under our TUAs meet the exception for allocating variable consideration to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation that is a series. As such, the variable consideration for the TUA is allocated to the period that the respective good or service is delivered to the customer.

For transactions where we receive consideration from the customer, we assess whether we are the principal or the agent in the arrangement. Arrangements where we have concluded that we act as a principal are presented within our Consolidated Statements of Operations on a gross basis, and arrangements where we have concluded that we act as an agent are presented within our Consolidated Statements of Operations on a net basis. For the years ended December 31, 2025, 2024 and 2023, we did not have any material revenue arrangements that were presented within our Consolidated Statements of Operations on a net basis.

See Note 12—Revenues for additional information regarding our revenues.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements. Our subsidiaries that are subject to such restrictions are required to deposit all cash received into reserve accounts controlled by the collateral trustee pursuant to the respective accounts agreement entered into with the collateral trustee for the benefit of the debt holders.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Current Expected Credit Losses

Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers contract and payment terms, the counterparty’s established credit rating and credit worthiness and other risks or available financial assurances. We calculate the allowance for credit losses under a probability-of-default method applied to pools of assets with similar risk characteristics and reflect credit enhancements such as letters of credit and guarantees to the extent that such enhancements are contractually linked to the underlying asset and with the same counterparty. Quarterly, we evaluate whether our method continues to be appropriate based on historical collections and additional information as it becomes available and adjust our reserve as necessary.

The following table reflects the changes in our current expected credit losses (in millions):
Year Ended December 31,
20252024
2023
Current expected credit losses, beginning of period
$4 $3 $5 
Charges (reversals), net— 1 (2)
Current expected credit losses, end of period
$4 $4 $3 

Inventory

LNG, natural gas and other commodity inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction or acquisition of assets, commissioning activities and costs that significantly extend the useful life or increase the functionality and/or capacity of an asset are capitalized. Expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of LNG terminal construction once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction.

Generally, costs that benefit us more broadly than for a specific project are capitalized prior to a project meeting the criteria otherwise necessary for capitalization and typically include land and land acquisition costs, preliminary material and equipment procurement and engineering design work.

Sales proceeds earned from volumes produced and sold during the commissioning phase of a respective Train, which includes test activities such as production and removal of LNG from storage, are offset against the cost of construction for the respective Train, net of associated costs, as such activities are necessary to test the facility and bring the asset to the condition necessary for its intended use.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except (1) assets under finance leases which are depreciated over the lesser of the respective lease term or the useful lives and (2) land which is not depreciated. Refer to Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category and Note 11—Leases for additional details of our finance leases. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the Consolidated Balance Sheets, and any resulting gains or losses on disposal are recorded in other operating costs and expenses.

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Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2025, 2024 and 2023.

Interest Capitalization

We capitalize interest costs as part of the historical cost of qualifying assets, mainly during the construction period of the qualifying assets, which primarily consists of LNG terminals and related assets. Upon placing the underlying asset in service, these costs are depreciated or amortized over the estimated useful life of the corresponding assets for which interest costs were incurred.
Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement, unless a derivative instrument satisfies criteria for, and we elect, the normal purchases and normal sales exception and account for the instrument under the accrual method of accounting, whereby the designated instrument’s revenues or expenses, as applicable, are recognized only upon delivery, receipt or realization of the underlying transaction.

We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2025, 2024 and 2023; therefore, the changes in the fair value of our derivative instruments are recorded in earnings.

As described in Concentration of Credit Risk below, the use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees. Variation margins or other daily margining posted for exchange-traded transactions that are contractually characterized as settlement of the respective derivative position are netted against the respective derivative asset or liability positions.
We have elected to report derivative assets and liabilities under master netting arrangements with the same counterparty on a net basis. Additionally, the fair value amounts recognized as cash collateral pledged or received, such as initial margins and other collateral that are not contractually characterized as settlement of the respective derivative positions, are offset against the fair value of derivatives executed with the same counterparty under a master netting arrangement. Collateral balances not offset against a derivative position are presented on our Consolidated Balance Sheets within margin deposits and other current liabilities. Derivative assets and liabilities not subject to master netting arrangements are presented net when we have a legally enforceable right and the intent to offset amounts with the same counterparty.

See Note 6—Derivative Instruments for additional details about our derivative instruments.

Leases

We determine if an arrangement is, or contains, a lease at inception of the arrangement. When we determine the arrangement is, or contains, a lease in which we are the lessee, we classify the lease as either an operating lease or a finance lease. Operating and finance leases are recognized on our Consolidated Balance Sheets by recording a lease liability
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representing the obligation to make future lease payments and a right-of-use asset representing the future right to use the underlying asset over the lease term.

Operating and finance lease right-of-use assets and liabilities are generally recognized based on the present value of minimum lease payments over the lease term. In determining the present value of minimum lease payments, we use the implicit interest rate in the lease if readily determinable. In the absence of a readily determinable implicit interest rate, we discount our expected future lease payments using the incremental borrowing rate of the relevant Cheniere entity, which can be a parent entity when the terms of the lease arrangements are significantly influenced by the parent’s credit standing. The incremental borrowing rate is an estimate of the interest rate that a given entity would have to pay to borrow on a collateralized basis over a similar term to that of the lease term. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability when they are reasonably certain to be exercised.

We have elected practical expedients to (1) omit leases with an initial term of 12 months or less from recognition on our Consolidated Balance Sheets and (2) to combine both the lease and non-lease components of an arrangement’s contractual consideration in calculating the right-of-use asset and lease liability for all classes of leased assets.

Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Lease expense for finance leases is recognized as the sum of the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities using the effective interest method over the lease term.

Certain of our leases also contain variable payments that are included in the right-of-use asset and lease liability only when the payments are in-substance fixed payments that are, in effect, unavoidable.

When we determine the arrangement is, or contains, a lease in which we are the lessor or sublessor, we assess classification of the lease as either an operating lease, sales-type lease or direct financing lease. All such arrangements have been assessed as operating leases and consist of sublessor arrangements in which we have not been relieved of our primary obligation under the original lease. Our sublessor arrangements are not recognized on our Consolidated Balance Sheets and we recognize income from fixed lease payments under these arrangements on a straight-line basis over the sublease term. We recognize income from variable lease payments in the period in which the changes in facts and circumstances on which the variable lease payments are based occur.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, consist principally of accounts receivable and contract assets related to our long-term SPAs, as our contracted LNG sales are primarily under SPAs with terms exceeding 10 years. As of December 31, 2025, we had SPAs with initial terms of 10 or more years with approximately 30 different third party customers, with customers under common control being considered a single customer. We are dependent on the respective customers’ creditworthiness and their ability to perform under their respective agreements. While substantially all of our long-term third party customer arrangements are executed with a creditworthy company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

While we use derivative instruments that expose us to counterparty credit risk, our underlying arrangements typically include provisions that protect us and our counterparties against such risk. For example, our commodity derivatives executed over-the-counter or through an exchange often require collateral that is returned to us (or to the counterparty) on or near the settlement date or are settled on a daily margin basis with investment grade financial institutions, and are primarily facilitated by independent system operators and by clearing brokers. For non-exchange traded transactions, payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds the pre-established credit limit with the counterparty. Our FX derivative instruments are placed with investment grade financial institutions whom we believe have insignificant credit risks.

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We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. Even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our assets.

Debt

Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Term debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and commitment fees. Costs associated with entering into a line of credit or on undrawn funds are presented as an asset and classified as current or non-current, consistent with the respective credit facility. As of December 31, 2025 and 2024, all of such costs were classified as other non-current assets, net, on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt except in the case of our credit facilities, in which such items are amortized on a straight-line basis over the contractual term of the facility. Amortization is recorded in interest expense, net of capitalized interest using the effective interest method.

We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:
•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt or equity agreement.
•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

Our real property lease agreements at the Sabine Pass LNG Terminal require us to surrender the LNG terminal in good order and repair, with normal wear and tear and casualty excepted, at the expiration of the term of the leases, with renewal options extending such terms up to 90 years. We have determined that the cost to surrender the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty excepted, is immaterial, thus we have not recorded an ARO associated with the Sabine Pass LNG Terminal.

Our Creole Trail Pipeline and Corpus Christi Pipeline are subject to regulations by the FERC for proper abandonment of a pipeline, including the disconnection of the pipeline from all sources and supplies of gas and other decommissioning costs. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the U.S. and intend to maintain them regularly. For these reasons, we have not recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline.

Share-based Compensation

We have awarded share-based compensation in the form of restricted stock shares, restricted stock units, performance stock units and phantom units, as further described in Note 15—Share-based Compensation. We initially measure share-based
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compensation based upon the estimated fair value of awards. The recognition period for these costs begins at the earlier of the applicable service inception date or grant date and continues throughout the requisite service period.

For equity-classified share-based compensation awards, compensation cost is recognized based on the grant-date fair value and not subsequently remeasured unless modified. For liability-classified share-based compensation awards that cash settle or include an election to be cash settled, compensation costs are remeasured at fair value through settlement or maturity. Except for awards that contain market conditions, the grant-date fair value is estimated based on our stock price on the grant date. The fair value of awards containing market conditions is estimated using a Monte Carlo model as of the grant date, which utilizes inputs such as expected stock volatility, risk-free rates and dividend yield.

For awards that contain graded vesting periods, the fair value is recognized as expense (net of any capitalization in accordance with GAAP) on a straight-line basis, generally over the term of the entire award, except when modifications may require an accelerated method. For awards that contain cliff vesting periods, the fair value is recognized as expense (net of any capitalization in accordance with GAAP) on a straight-line basis over the requisite service period.

For awards with both time and performance-based conditions, we recognize compensation cost based on the probable outcome of the performance condition at each reporting period.

We account for forfeitures as they occur.

Foreign Currency

The functional currency of all of our subsidiaries is the U.S. dollar. Certain of our subsidiaries transact in currencies outside of the U.S. dollar, which gives rise to the recognition of transaction gains and losses based on the change in exchange rates between the U.S. dollar and the currency in which the foreign currency transaction is denominated. During the years ended December 31, 2025, 2024 and 2023, we recognized net transaction gains (losses) totaling $(5) million, $1 million and $1 million, respectively, excluding gains and losses from FX derivatives which are further detailed in Note 6—Derivative Instruments. Substantially all of our transaction gains and losses related to commercial transactions were executed by Cheniere Marketing, primarily consisting of Euro denominated receivables, which are presented within LNG revenues in our Consolidated Statements of Operations with the underlying activities.

Income Taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in our Consolidated Financial Statements. Deferred tax assets and liabilities are included in our Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes.
A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that some or all of our deferred tax assets will not be realized. We evaluate the realizability of our deferred tax assets as of each reporting date, weighing all positive and negative evidence. The assessment requires significant judgment and is performed in each of our applicable jurisdictions. In making such determination, we consider various factors such as historical profitability, future projections of sustained profitability underpinned by fixed-price long-term SPAs and reversal of existing deferred tax liabilities.

We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination.

The Inflation Reduction Act of 2022 (“IRA”) imposed a 15% CAMT effective in 2023, that is based on 15% of an applicable corporation’s adjusted financial statement income. We have elected to account for the effects of the CAMT on deferred tax assets, carryforwards and tax credits in the period they arise.

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Net Income or Loss Per Share

Basic net income or loss per share attributable to common stockholders excludes dilution and is computed by dividing net income or loss attributable to common stockholders during the period by the weighted average number of common shares outstanding during the period. Diluted net income or loss per share reflects potential dilution from our unvested stock and is computed by dividing net income or loss attributable to common stockholders by the weighted average number of common shares outstanding during the period, which is increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued. The additional common shares are calculated using the treasury stock method, which assumes the unvested shares are issued at the beginning of the period (or at the time of grant, if later) and that the amount of unrecognized compensation cost is used to purchase our common stock at the average market price during the period. However, if the effect of any additional securities are anti-dilutive (i.e., resulting in a higher net income per share or lower net loss per share), they are excluded from the dilutive net income or loss computation.

Refer to Note 17—Net Income per Share Attributable to Common Stockholders for additional details of the computation for the years ended December 31, 2025, 2024 and 2023.

Recent Accounting Standards

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740), which we adopted prospectively on December 31, 2025. This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The adoption of this guidance did not have an impact on our results of operations and financial condition, but updated the required disclosures — see Note 14—Income Taxes.

ASU 2024-03

In November 2024, the FASB issued ASU No. 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, as clarified by ASU No. 2025-01 in January 2025. This guidance requires disaggregated disclosures about certain income statement expense line items on an annual and interim basis. We continue to evaluate the impact of the provisions of this guidance on our disclosures, but plan to adopt this guidance prospectively and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2027.

NOTE 3—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):
December 31,
20252024
Trade receivables
SPL and CCL
$755 $548 
Cheniere Marketing
472 109 
       Other subsidiaries10 4 
Total trade receivables1,237 661 
Other receivables
SPL and CCL
54 19 
Other subsidiaries89 47 
Total other receivables143 66 
Total trade and other receivables, net of current expected credit losses$1,380 $727 

Upon collection of our receivables by SPL and CCL, cash will be immediately restricted for the payment of liabilities related to the Liquefaction Projects. See Note 2—Summary of Significant Accounting Policies for further discussion of our Restricted Cash and Cash Equivalents.

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NOTE 4—INVENTORY

Inventory consisted of the following (in millions):
December 31,
20252024
Materials$275 $226 
LNG84 93 
LNG in-transit102 137 
Natural gas33 30 
Other30 15 
Total inventory$524 $501 

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
 
Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):
Useful lifeDecember 31,
(years)20252024
Terminal and related assets  
Terminal and interconnecting pipeline facilities
6 - 50
$38,422 $34,282 
Land745 465 
Construction-in-process4,096 5,486 
Accumulated depreciation(8,434)(7,231)
Total terminal and related assets, net of accumulated depreciation34,829 33,002 
Fixed assets and other assets
Fixed assets and other assets
3 - 10
260 260 
Accumulated depreciation(195)(188)
Total fixed assets and other assets, net of accumulated depreciation65 72 
Assets under finance leases
Marine assets
5 - 20
1,060 587 
Accumulated depreciation(199)(109)
Total assets under finance leases, net of accumulated depreciation861 478 
Property, plant and equipment, net of accumulated depreciation$35,755 $33,552 

The following table shows depreciation expense and offsets to terminal assets (in millions):
Year Ended December 31,
202520242023
Depreciation expense$1,320 $1,213 $1,190 
Sales proceeds earned from commissioning sales of LNG offset to terminal assets (1)187 — — 
(1)We realize offsets to terminal assets for sales proceeds from commissioning volumes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

NOTE 6—DERIVATIVE INSTRUMENTS

We have the following derivative instruments:
•commodity derivatives consisting of the following (collectively, “Commodity Derivatives”):
◦natural gas and power supply contracts, including our IPM agreements, for the development, commissioning and operation of the Liquefaction Projects and expansion projects, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”); and,
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◦LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively, “LNG Trading Derivatives”); and
•FX contracts to hedge exposure to currency risk associated with cash flows denominated in currencies other than U.S. dollar (“FX Derivatives”), associated with both LNG Trading Derivatives and operations in countries outside of the U.S.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):
Fair Value Measurements as of
December 31, 2025December 31, 2024
Quoted Prices in Active Markets
(Level 1)		Significant Other Observable Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		TotalQuoted Prices in Active Markets
(Level 1)		Significant Other Observable Inputs
(Level 2)		Significant Unobservable Inputs
(Level 3)		Total
Liquefaction Supply Derivatives asset (liability)
$— $(37)$2,902 $2,865 $— $59 $(801)$(742)
LNG Trading Derivatives asset (liability)
— (17)— (17)— 17 — 17 
FX Derivatives asset (liability)
— (2)— (2)— 16 — 16 

We value the Liquefaction Supply Derivatives and LNG Trading Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data. We value our FX Derivatives with a market approach using observable FX rates and other relevant data.

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models, which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. As applicable to our natural gas supply contracts, our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2025:
Net Fair Value Asset
(in millions)
Valuation ApproachSignificant Unobservable InputRange of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives$2,902Market approach incorporating present value techniques
Henry Hub basis spread
$(4.085) - $0.195 / $(0.120)
Option pricing model
International LNG pricing spread, relative to Henry Hub (2)
60% - 407% / 175%
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):
Year Ended December 31,
202520242023
Balance, beginning of period$(801)$(2,178)$(9,924)
Realized and change in fair value gains included in net income (1):
Included in cost of sales, existing deals (2)2,178 716 5,685 
Included in cost of sales, new deals (3)709 22 15 
Purchases and settlements:
Purchases (4)— — — 
Settlements (5)822 639 2,045 
Transfers out of level 3 (6)(6)— 1 
Balance, end of period$2,902 $(801)$(2,178)
Favorable changes in fair value relating to instruments still held at the end of the period
$2,887 $738 $5,700 
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period, which continue to exist at the end of the period.
(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Commodity Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub, global LNG or other natural gas price indices. As of December 31, 2025, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

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Cheniere Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximately one year.

The following table shows the notional amounts of our Commodity Derivatives:
December 31, 2025December 31, 2024
Liquefaction Supply Derivatives (1)LNG Trading DerivativesLiquefaction Supply Derivatives (1)LNG Trading Derivatives
Notional amount, net (in TBtu)12,218 39 12,503 (8)
(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both December 31, 2025 and 2024.

The following table shows the effect and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations (in millions):
Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)
Year Ended December 31,
202520242023
LNG Trading DerivativesLNG revenues$389 $(111)$139 
LNG Trading DerivativesCost of sales(62)(2)(132)
Liquefaction Supply Derivatives (2)LNG revenues1 (3)(5)
Liquefaction Supply Derivatives (2)Cost of sales3,562 1,390 7,912 
(1)Fair value fluctuations associated with activities of our Commodity Derivatives are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery.

FX Derivatives

Cheniere Marketing holds FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives are executed primarily to economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions that are denominated in a currency other than the U.S. dollar. The terms of FX Derivatives range up to approximately one year.
The total notional amount of our FX Derivatives was $783 million and $642 million as of December 31, 2025 and 2024, respectively.

The following table shows the effect and location of our FX Derivatives recorded on our Consolidated Statements of Operations (in millions):
Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations LocationYear Ended December 31,
202520242023
FX Derivatives
LNG revenues$(46)$41 $(24)

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The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions):
December 31, 2025
Liquefaction Supply Derivatives
LNG Trading Derivatives
FX Derivatives
Total
Consolidated Balance Sheets Location
Current derivative assets$7 $1 $1 $9 
Derivative assets4,663 — — 4,663 
Total derivative assets4,670 1 1 4,672 
Current derivative liabilities(597)(18)(3)(618)
Derivative liabilities(1,208)— — (1,208)
Total derivative liabilities(1,805)(18)(3)(1,826)
Derivative asset (liability), net$2,865 $(17)$(2)$2,846 
December 31, 2024
Liquefaction Supply Derivatives
LNG Trading Derivatives
FX Derivatives
Total
Consolidated Balance Sheets Location
Current derivative assets$105 $32 $18 $155 
Derivative assets1,903 — — 1,903 
Total derivative assets2,008 32 18 2,058 
Current derivative liabilities(885)(15)(2)(902)
Derivative liabilities(1,865)— — (1,865)
Total derivative liabilities(2,750)(15)(2)(2,767)
Derivative asset (liability), net$(742)$17 $16 $(709)

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Consolidated Balance Sheets Presentation

The following table reconciles the fair value of our derivative assets and liabilities on a gross basis, by contract, to net amounts as presented on our Consolidated Balance Sheets after offsetting for any balances with the same counterparty under master netting arrangements or other relevant netting criteria under GAAP (in millions):
Liquefaction Supply Derivatives
LNG Trading Derivatives
FX Derivatives
As of December 31, 2025
Gross assets$5,688 $2 $2 
Offsetting amounts(1,018)(1)(1)
Net assets (1)$4,670 $1 $1 
Gross liabilities$(1,855)$(54)$(5)
Offsetting amounts50 36 2 
Net liabilities (2)$(1,805)$(18)$(3)
As of December 31, 2024
Gross assets$3,064 $42 $25 
Offsetting amounts(1,056)(10)(7)
Net assets (1)$2,008 $32 $18 
Gross liabilities$(2,790)$(16)$(3)
Offsetting amounts40 1 1 
Net liabilities (2)$(2,750)$(15)$(2)
(1)Includes current and non-current derivative assets of $9 million and $4,663 million, respectively, as of December 31, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.
(2)Includes current and non-current derivative liabilities of $618 million and $1,208 million, respectively, as of December 31, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

The table below shows the collateral balances that are recorded within margin deposits and other current liabilities that are not netted on our Consolidated Balance Sheets (in millions):
Consolidated Balance Sheets LocationDecember 31,
20252024
Liquefaction Supply DerivativesMargin deposits$20 $18 
Liquefaction Supply DerivativesOther current liabilities3 — 
LNG Trading DerivativesMargin deposits56 110 
LNG Trading DerivativesOther current liabilities5 — 

NOTE 7—OTHER NON-CURRENT ASSETS, NET

Other non-current assets, net consisted of the following (in millions):
December 31,
20252024
Contract assets, net of current expected credit losses$394 $325 
Advances to service providers196 203 
Tax-related assets90 20 
Equity method investments78 129 
Goodwill77 77 
Debt issuance costs and deferred commitment fees, net of accumulated amortization66 65 
Other, net159 80 
Total other non-current assets, net$1,060 $899 

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NOTE 8—NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. We own a 48.6% limited partner interest in CQP, and we also own all of the 2% general partner interest and 100% of the incentive distribution rights in CQP. The remaining 49.4% non-controlling limited partner interest in CQP is held by affiliates of Blackstone Inc. and Brookfield Asset Management, Inc. as well as the public.
CQP is a limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG Terminal and related assets. Our wholly-owned subsidiary, Cheniere Partners GP, is the general partner of CQP. The board of directors of Cheniere Partners GP includes three directors appointed by CQP Holdco LP (an affiliate of Blackstone Inc. and Brookfield Asset Management Inc.) (“CQP Holdco”), four directors appointed by us and four independent directors mutually agreed upon by CQP Holdco and us and appointed by us. In addition, we provided CQP Holdco with a right to maintain one board seat on our Board. A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by CQP Holdco, two directors appointed by us and two independent directors. CQP Holdco will no longer be entitled to appoint Cheniere Partners GP directors in the event that CQP Holdco’s ownership in CQP is less than 20% of outstanding common units.

As a holder of common units of CQP, we are not obligated to fund losses of CQP. However, our capital account, which would be considered in allocating the net assets of CQP were it to be liquidated, continues to share in losses of CQP. We have determined that Cheniere Partners GP is a VIE and that we, as the holder of the equity at risk, do not have a controlling financial interest due to the rights held by CQP Holdco. However, we continue to consolidate CQP as a result of CQP Holdco’s right to maintain one board seat on our Board which creates a de facto agency relationship between CQP Holdco and us. GAAP requires that when a de facto agency relationship exists, one of the members of the de facto agency relationship must consolidate the VIE based on certain criteria. As a result, we consolidate CQP in our Consolidated Financial Statements.

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The following table presents the summarized consolidated assets and liabilities (in millions) of our consolidated VIEs, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of the respective VIEs. In addition, there is no recourse to us for the consolidated VIEs’ liabilities. The assets and liabilities in the table below exclude intercompany balances between the respective VIEs and Cheniere that eliminate in our Consolidated Financial Statements.
December 31,
20252024
ASSETS 
Current assets  
Cash and cash equivalents$182 $270 
Restricted cash and cash equivalents22 125 
Trade and other receivables, net of current expected credit losses512 381 
Inventory186 154 
Current derivative assets— 84 
Margin deposits11 13 
Other current assets, net55 54 
Total current assets968 1,081 
Property, plant and equipment, net of accumulated depreciation15,397 15,880 
Operating lease assets77 80 
Derivative assets541 98 
Other non-current assets, net287 206 
Total assets$17,270 $17,345 
LIABILITIES  
Current liabilities  
Accounts payable$58 $70 
Accrued liabilities1,000 881 
Current debt, net of unamortized discount and debt issuance costs306 351 
Deferred revenue119 120 
Current operating lease liabilities5 4 
Current derivative liabilities164250 
Other current liabilities11 16 
Total current liabilities1,663 1,692 
Long-term debt, net of unamortized discount and debt issuance costs14,161 14,761 
Operating lease liabilities73 76 
Derivative liabilities900 1,213 
Other non-current liabilities159 176 
Total liabilities$16,956 $17,918 

NOTE 9—ACCRUED LIABILITIES
 
Accrued liabilities consisted of the following (in millions): 
December 31,
20252024
Natural gas purchases$1,209 $886 
Terminal and related asset costs306 272 
Interest costs and related debt fees219 214 
Compensation and benefits215 283 
Tax-related liabilities90 472 
Other accrued liabilities42 52 
Total accrued liabilities$2,081 $2,179 
 
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NOTE 10—DEBT
Debt consisted of the following (in millions): 
December 31,
20252024
SPL:
Senior Secured Notes:
5.625% due 2025
$— $300 
5.875% due 2026 (the “2026 SPL Senior Notes”) (1)
200 1,500 
5.00% due 2027
1,500 1,500 
4.200% due 2028
1,350 1,350 
4.500% due 2030
2,000 2,000 
due 2037 with weighted average rate of 4.747% and 4.746% at December 31, 2025 and 2024, respectively (2)
1,730 1,782 
Total SPL Senior Secured Notes
6,780 8,432 
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)
— — 
Total debt - SPL
6,780 8,432 
CQP:
Senior Notes:
4.500% due 2029 (the “2029 CQP Senior Notes”)
1,500 1,500 
4.000% due 2031 (the “2031 CQP Senior Notes”)
1,500 1,500 
3.25% due 2032 (the “2032 CQP Senior Notes”)
1,200 1,200 
5.950% due 2033
1,400 1,400 
5.750% due 2034
1,200 1,200 
5.550% due 2035
1,000 — 
Total CQP Senior Notes
7,800 6,800 
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)
— — 
Total debt - CQP
7,800 6,800 
CCH:
Senior Secured Notes:
5.125% due 2027
1,201 1,201 
3.700% due 2029
1,125 1,125 
3.788% weighted average rate due 2039 (2)
2,539 2,539 
Total CCH Senior Secured Notes
4,865 4,865 
Term loan facility agreement (the “CCH Credit Facility”)
550 — 
Working capital facility agreement (the “CCH Working Capital Facility”)
— — 
Total debt - CCH
5,415 4,865 
Cheniere:
Senior Notes:
4.625% due 2028
1,500 1,500 
5.650% due 2034
1,500 1,500 
Total Cheniere Senior Notes
3,000 3,000 
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)
— — 
Total debt - Cheniere
3,000 3,000 
Total debt22,995 23,097 
Current debt, net of unamortized discount and debt issuance costs (2)(306)(351)
Unamortized discount and debt issuance costs(182)(192)
Total long-term debt, net of unamortized discount and debt issuance costs$22,507 $22,554 
(1)Subsequently in February 2026, SPL redeemed the remaining $200 million aggregate principal amount of its 2026 SPL Senior Notes.
(2)Includes notes that amortize based on a fixed amortization schedule as set forth in their respective indentures.
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Senior Notes

SPL Senior Secured Notes

The SPL Senior Secured Notes are senior secured obligations of SPL, ranking equally in right of payment with SPL’s other existing and future senior debt that is secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the SPL Senior Secured Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may, at any time, redeem all or part of the SPL Senior Secured Notes at specified prices set forth in the respective indentures governing the SPL Senior Secured Notes, plus accrued and unpaid interest, if any, prior to the date of redemption. The series of SPL Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

CQP Senior Notes

The CQP Senior Notes are jointly and severally guaranteed by each of CQP’s current and certain future subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are senior obligations of CQP, ranking equally in right of payment with CQP’s other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of CQP’s secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the 2029 CQP Senior Notes, 2031 CQP Senior Notes and 2032 CQP Senior Notes will be secured by a first-priority lien (subject to permitted encumbrances) on substantially all the existing and future tangible and intangible assets and rights of CQP and the CQP Guarantors, as well as the equity interests in the CQP Guarantors. The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of any other senior secured obligations. CQP may, at any time, redeem all or part of the CQP Senior Notes at specified prices set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, prior to the date of redemption.

CCH Senior Secured Notes

The CCH Senior Secured Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The CCH Senior Secured Notes are senior secured obligations of CCH, ranking senior in right of payment to any and all of CCH’s future indebtedness that is subordinated to the CCH Senior Secured Notes and equal in right of payment with CCH’s other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Secured Notes. The CCH Senior Secured Notes are secured by a first-priority security interest in substantially all of CCH’s and the CCH Guarantors’ assets. CCH may, at any time, redeem all or part of the CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, prior to the date of redemption. The series of CCH Senior Secured Notes due in 2039 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

Cheniere Senior Notes

The Cheniere Senior Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the Cheniere Senior Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The Cheniere Senior Notes are currently unsecured, but in certain instances may become secured in the future in connection with the incurrence of additional secured indebtedness by us. When required, the Cheniere Senior Notes will be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries), which liens rank pari passu with the liens securing the Cheniere Revolving Credit Facility. As of December 31, 2025, the Cheniere Senior Notes are not guaranteed by any of our subsidiaries. In the future, any subsidiary that guarantees any of our material indebtedness will also guarantee the Cheniere Senior Notes. We may, at any time, redeem all or part of the Cheniere Senior Notes at specified
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prices set forth in the indenture governing the Cheniere Senior Notes, plus accrued and unpaid interest, if any, prior to the date of redemption.
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2025 (in millions):
Years Ending December 31,Principal Payments
2026$307 
20272,933 
20283,597 
20292,923 
20302,311 
Thereafter10,924 
Total$22,995 

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of December 31, 2025 (in millions):
SPL Revolving Credit Facility (1)
CQP Revolving Credit Facility (2)
CCH Credit Facility (3)
CCH Working Capital Facility (4)
Cheniere Revolving Credit Facility (5)
Total facility size$1,000 $1,000 $3,260 $1,500 $1,250 
Less:
Outstanding balance— — 550 — — 
Letters of credit issued176 — — 110 — 
Available commitment$824 $1,000 $2,710 $1,390 $1,250 
Priority rankingSenior securedSenior unsecuredSenior securedSenior securedSenior unsecured
Interest rate on available balance (6)
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5%
SOFR plus margin of 1.075% - 2.00% or base rate plus 0.075% - 1.00%
Weighted average interest rate of outstanding balancen/an/a5.316%n/an/a
Commitment fees on undrawn balance (6)
0.075% - 0.30%
0.10% - 0.30%
0.525%
0.10% - 0.20%
0.090% - 0.300%
Letter of credit fees (6)
1.0% - 1.75%
1.125% - 2.0%
N/A
1.0% - 1.5%
1.075% - 2.00%
Maturity dateJune 23, 2028June 23, 2028(7)June 15, 2027August 1, 2030
(1)The obligations of SPL under the SPL Revolving Credit Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Secured Notes. The SPL Revolving Credit Facility contains customary contractual conditions for extensions of credit.
(2)The obligations under the CQP Revolving Credit Facility are jointly, severally and unconditionally guaranteed by Cheniere Energy Investments, LLC, SPLNG, CTPL, Sabine Pass LNG-GP, LLC, Sabine Pass Tug Services, LLC and Cheniere Pipeline GP Interests, LLC, each subsidiaries of CQP.
(3)The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by Cheniere CCH Holdco I, LLC, the direct parent company of CCH, of its limited liability company interests in CCH.
(4)The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.
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(5)In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.
(6)The margins on the interest rate, the commitment fees and the letter of credit fees are subject to change based on the applicable entity’s credit rating. The interest rate and the commitment fees of the Cheniere Revolving Credit Facility are also based on the achievement of certain methane emissions management standards.
(7)The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.

Restrictive Debt Covenants

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay dividends or distributions. For example, SPL and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. Additionally, as described in Note 2—Summary of Significant Accounting Policies, our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Projects as required under certain debt arrangements. At December 31, 2025, our restricted net assets of consolidated subsidiaries, as imposed under certain debt agreements and certain other third party agreements, were approximately $407 million.
As of December 31, 2025, we were, and each of our subsidiaries was, in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense, net of capitalized interest, consisted of the following (in millions):
 Year Ended December 31,
202520242023
Total interest cost$1,197 $1,226 $1,265 
Capitalized interest(249)(216)(124)
Total interest expense, net of capitalized interest$948 $1,010 $1,141 

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our senior notes (in millions):
 December 31, 2025December 31, 2024
 Carrying
Amount (1)		Estimated
Fair Value (2)		Carrying
Amount (1)		Estimated
Fair Value (2)
Senior notes
$22,995 $22,313 $23,097 $22,220 
(1)Carrying amounts exclude unamortized discount and debt issuance costs.
(2)As of December 31, 2025 and 2024, $3.1 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

The estimated fair value of any outstanding borrowings under our credit facilities approximates the principal amount outstanding because the interest rates are indexed to market rates and the debt may be repaid, in full or in part, at any time without penalty.

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NOTE 11—LEASES

We are the lessee of LNG vessels leased under time charters (“vessel charters”) as well as tug vessels, office space and facilities, land sites and equipment.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):
December 31,
Consolidated Balance Sheets Location20252024
Right-of-use assets—OperatingOperating lease assets$2,700 $2,684 
Right-of-use assets—FinancingProperty, plant and equipment, net of accumulated depreciation861 478 
Total right-of-use assets$3,561 $3,162 
Current operating lease liabilitiesCurrent operating lease liabilities$539 $592 
Current finance lease liabilitiesOther current liabilities88 44 
Non-current operating lease liabilitiesOperating lease liabilities2,163 2,090 
Non-current finance lease liabilitiesOther non-current liabilities843 486 
Total lease liabilities$3,633 $3,212 

The following table shows the classification and location of our lease costs on our Consolidated Statements of Operations (in millions):
Consolidated Statements of Operations Location
Year Ended December 31,
202520242023
Operating lease cost (a)Operating costs and expenses (1)$796 $839 $783 
Finance lease cost:
Amortization of right-of-use assetsDepreciation, amortization and accretion expense90 53 50 
Interest on lease liabilitiesInterest expense, net of capitalized interest52 35 35 
Total lease cost$938 $927 $868 
(a) Included in operating lease cost:
Short-term lease costs$5 $16 $33 
Variable lease costs23 14 17 
(1)Presented in the appropriate line item within operating costs and expenses, consistent with the nature of our use of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of December 31, 2025 are as follows (in millions): 
Years Ending December 31,Operating LeasesFinance Leases
2026$670 $142 
2027586 143 
2028404 146 
2029315 146 
2030300 146 
Thereafter1,027 500 
Total lease payments (1)3,302 1,223 
Less: Interest(600)(292)
Present value of lease liabilities$2,702 $931 
(1)Does not include approximately $4.3 billion of legally binding minimum payments for leases executed as of December 31, 2025 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.
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The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our operating leases and finance leases:
December 31, 2025December 31, 2024
Operating LeasesFinance LeasesOperating LeasesFinance Leases
Weighted-average remaining lease term (in years)7.48.57.08.8
Weighted-average discount rate (1)5.2%6.6%5.0%7.4%
(1)The weighted average discount rate is impacted by certain finance leases that commenced prior to the adoption of the current leasing standard under GAAP. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.

The following table includes other quantitative information for our operating and finance leases (in millions):
Year Ended December 31,
202520242023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases$764 $803 $720 
Operating cash flows from finance leases52 35 35 
Financing cash flows from finance leases73 35 28 
Right-of-use assets obtained in exchange for operating lease liabilities (1)639 713 646 
Right-of-use assets obtained in exchange for finance lease liabilities (2)472 61 8 
(1)Net of $33 million reclassified from operating leases to finance leases during the year ended December 31, 2024, as a result of modifications of the underlying tug vessel leases.
(2)Net of $15 million reclassified from finance leases to operating leases during the year ended December 31, 2024, as a result of modifications of the underlying tug vessel leases.

LNG Vessel Subleases

We sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. All of our sublease arrangements have been assessed as operating leases. The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):
Year Ended December 31,
202520242023
Fixed income$90 $283 $446 
Variable income55 39 57 
Total sublease income$145 $322 $503 

As of December 31, 2025, the aggregate future annual minimum sublease payment to be received from LNG vessel subleases was $5 million and is expected to be received during the year ending December 31, 2026.

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NOTE 12—REVENUES

The following table represents a disaggregation of revenue earned (in millions):
Year Ended December 31,
202520242023
Revenues from contracts with customers
LNG revenues (excluding net derivative gain (loss) below)
$19,091 $14,972 $19,459 
Regasification revenues136 135 135 
     Other revenues (1)237 307 187 
Total revenues from contracts with customers19,464 15,414 19,781 
Net derivative gain (loss) (see Note 6)
344 (73)110 
Sublease income (see Note 11)
145 322 503 
Other revenues23 40 — 
Total revenues$19,976 $15,703 $20,394 
(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

LNG Revenues

We have numerous SPAs with third party customers for the sale of LNG on an FOB basis or a DAP basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train.

We intend to primarily use LNG sourced from our Sabine Pass LNG Terminal or our Corpus Christi LNG Terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $226 million, $280 million and $359 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Regasification Revenues

The Sabine Pass LNG Terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 1 Bcf/d of the regasification capacity at the Sabine Pass LNG Terminal has been reserved under a long-term TUA with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”) under which they are required to pay fixed monthly fees to SPLNG, regardless of their use of the LNG terminal. The aggregate annual payment of approximately $125 million (indexed for inflation) they are required to pay under the 20 year contract that commenced in 2009 represents fixed consideration. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Approximately 2 Bcf/d of regasification capacity of the Sabine Pass LNG Terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

In 2012, SPL entered into a partial TUA assignment agreement with TotalEnergies, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit SPL to more flexibly manage its LNG storage capacity. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred to TotalEnergies are recognized in operating and maintenance expense. During the years ended December 31, 2025, 2024 and 2023, SPL recorded $134 million, $133 million and $132 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

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Contract Assets and Liabilities

The following table shows our contract assets, net of current expected credit losses, which are included in other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):
December 31,
20252024
Contract assets, net of current expected credit losses$424 $331 

Contract assets include our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due and have primarily arisen from certain SPAs that have tiered payment structures.

The following table reflects the changes in our contract liabilities, which are included in deferred revenue and other non-current liabilities on our Consolidated Balance Sheets (in millions):
Year Ended December 31, 2025
Deferred revenue, beginning of period$318 
Cash received but not yet recognized in revenue123 
Revenue recognized from prior period deferral(169)
Deferred revenue, end of period$272 

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. The change in deferred revenue between the years ended December 31, 2025 and 2024 is primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration, which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:
December 31, 2025December 31, 2024
Unsatisfied Transaction Price (in billions)Weighted Average Recognition Timing (years) (1)Unsatisfied Transaction Price (in billions)Weighted Average Recognition Timing (years) (1)
LNG revenues$107.7 8$104.7 8
Regasification revenues0.4 20.5 3
Total revenues$108.1 $105.2 
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price, and allocable to wholly unsatisfied future performance obligations or otherwise constrained, will vary based on (1) the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, (2) adjustments to the consumer price index and (3) the outcome of certain contingent events, including the achievement of milestones upon which delivery of LNG under certain contracts is conditioned.

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The following table summarizes the percentage of variable consideration earned under contracts with customers included in the table above:
Year Ended December 31,
20252024
LNG revenues67 %59 %
Regasification revenues8 %8 %

NOTE 13—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
Year Ended December 31,
202520242023
Other revenues
Operating agreement and construction management agreement with equity method investee (1)$1 $9 $10 
Operating and maintenance expense
Natural gas transportation and storage agreements with equity method investees (1)32 24 9 
Natural gas transportation and storage agreements with other related party (2)28 73 62 
(1)On February 13, 2025, we sold all of our equity interests in one of our equity method investments to a third party. Additionally, we assigned certain operating and construction management agreements to the purchaser of such interests. Included in the table above are $1 million, $9 million and $10 million of other revenues and $1 million, $8 million and $9 million of operating and maintenance expense from the investee during the years ended December 31, 2025, 2024 and 2023, respectively.
(2)These arrangements were with a party that was related to the entity that indirectly owns a portion of CQP’s limited partner interests. Due to the sale of such interests by that entity effective May 13, 2025, this party is no longer considered a related party as of that date.

Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):
December 31,
20252024
Trade and other receivables, net of current expected credit losses$— $4 
Accrued liabilities3 8 

NOTE 14—INCOME TAXES

The jurisdictional components of income before income taxes and non-controlling interests on our Consolidated Statements of Operations are as follows (in millions):
Year Ended December 31,
202520242023
U.S. federal$7,239 $4,696 $11,176 
International1,043 607 3,402 
Total income before income taxes and non-controlling interests$8,282 $5,303 $14,578 
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Income tax provision included in our reported net income consisted of the following (in millions): 
Year Ended December 31,
202520242023
Current:
U.S. federal$(383)$471 $130 
State1 2 1 
Foreign11 8 (1)
Total current(371)481 130 
Deferred:
U.S. federal1,846 319 2,377 
State12 9 15 
Foreign1 2 (3)
Total deferred1,859 330 2,389 
Total income tax provision$1,488 $811 $2,519 
 
The table below provides the updated requirements of ASU No. 2023-09 for 2025. See Note 2—Summary of Significant Accounting Policies for additional details on the adoption of ASU No. 2023-09.

Our income tax rates do not bear a customary relationship to statutory income tax rates. A reconciliation of the U.S. federal statutory income tax rate of 21% to our effective income tax rate for the year ended December 31, 2025 is as follows: 
Year Ended December 31, 2025
Amount
(in millions)		Percent (2)
U.S. federal statutory tax rate$1,739 21.0 %
State and local income taxes, net of federal income tax effect (1)11 0.1 
Foreign tax effects
United Kingdom
Cheniere Marketing income not taxable in the U.K. under transfer pricing principles(249)(3.0)
Other40 0.5 
Other foreign jurisdictions2 — 
Effects of cross-border tax laws(2)— 
Tax credits(4)(0.1)
Changes in valuation allowance54 0.7 
Nontaxable or nondeductible items
CQP income not taxable to Cheniere(313)(3.8)
Other9 0.1 
Changes in unrecognized tax benefits3 — 
Other adjustments
Cheniere Marketing income taxable in the U.S. under transfer pricing principles209 2.5 
Other(11)— 
Effective tax rate as reported$1,488 18.0 %
(1)State taxes in Louisiana and Texas contributed to the majority of the tax effect in this category.
(2)The percentages in the table may not recalculate exactly due to rounding as the percentages are calculated based on whole numbers, not the rounded numbers presented.

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As previously disclosed for the years ended December 31, 2024 and 2023, prior to the adoption of ASU 2023-09, a reconciliation of the U.S. federal statutory income tax rate of 21% to our effective income tax rate was as follows:
Year Ended December 31,
20242023
U.S. federal statutory tax rate21.0 %21.0 %
Income not taxable to Cheniere(5.0)(3.1)
Foreign-derived intangible income deduction(1.0)(0.7)
Changes in valuation allowance(0.7)— 
Other1.0 0.1 
Effective tax rate as reported15.3 %17.3 %

Significant components of our deferred tax assets and liabilities are as follows (in millions): 
December 31,
20252024
Deferred tax assets  
Net operating loss (“NOL”) carryforwards
U.S. federal$245 $313 
State119 119 
Tax Credits
CAMT carryforward— 383 
Other tax credits50 40 
Operating lease liabilities566 562 
Other447 306 
Less: valuation allowance (1)(170)(110)
Total deferred tax assets1,257 1,613 
Deferred tax liabilities 
Investment in partnerships(375)(305)
Property, plant and equipment(3,277)(2,459)
Operating lease assets(553)(548)
Derivative instruments(696)(108)
Other(42)(30)
Total deferred tax liabilities(4,943)(3,450)
Net deferred tax liabilities$(3,686)$(1,837)
(1)Valuation allowance primarily relates to a valuation allowance recorded on U.S. federal capital loss carryforwards and state NOL carryforwards and increased by $60 million during the year ended December 31, 2025 primarily due to a capital loss carryforward generated in the current year that we do not expect to realize before expiration. The valuation allowance decreased by $37 million during the year ended December 31, 2024 and increased by $4 million during the year ended December 31, 2023.

NOL and tax credit carryforwards

As of December 31, 2025, we had U.S. federal and state NOL carryforwards of approximately $1.2 billion and $2.2 billion, respectively. All of our NOLs have an indefinite carryforward period.

As of December 31, 2025, our other tax credits expire between 2028 and 2035.

Our NOL and tax credit carryforwards are not subject to, nor impacted by, any prior tax ownership change. We continue to monitor public trading activity in our shares to identify potential tax ownership changes that could impact our timing and ability to utilize such attributes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
Tax Law Changes

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting Foreign Derived Intangible Income (“FDII”) deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.
The legislation did not have a material impact on our income tax expense for the year ended December 31, 2025, and it did not materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA deferred our tax liability, ultimately reducing our 2025 income taxes payable to a nominal amount, primarily due to the accelerated tax deduction on qualifying Corpus Christi Stage 3 Project assets.
On September 30, 2025, the Internal Revenue Service issued Notice 2025-49, which includes, among other provisions, revised interim rules for calculating CAMT adjusted financial statement income, including rules allowing us to utilize and benefit from our existing net operating loss carryovers for both CAMT and regular tax in the same period. As a result, our cash tax obligations have been deferred, and we received a refund of $380 million of previously paid CAMT in December 2025.
Unrecognized Tax Benefits

As of December 31, 2025, 2024 and 2023, there were $63 million, $65 million and $66 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate in future periods. Interest and penalties related to income tax matters are recognized as part of income tax provision. Interest and penalties recognized as part of income tax provision was $6 million, $6 million and $4 million for the years ended December 31, 2025, 2024 and 2023, respectively, and cumulative accrued interest was $15 million and $10 million as of December 31, 2025 and 2024, respectively.

We are subject to tax in the U.S. and various state and foreign jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. Federal tax returns for the years after 2017, United Kingdom tax returns for the years after 2020, Louisiana tax returns for the years after 2021 and Texas tax returns for the years after 2020 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

A reconciliation of the beginning and ending amounts of our unrecognized tax benefits is as follows (in millions): 
Year Ended December 31,
202520242023
Balance at beginning of the year$72 $73 $74 
Statute of limitations expiration(3)— — 
Reductions for tax positions of prior years— (1)(1)
Balance at end of the year$69 $72 $73 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following is a supplemental schedule of cash paid for income taxes, net of refunds, for the year ended December 31, 2025 (in millions):
Year Ended December 31,
2025
U.S. federal$47 
State and local2 
Foreign
United Kingdom(18)
Other1 
Total Foreign(17)
Total income taxes paid, net of refunds received$32 

We received an aggregate of $92 million in income tax refunds, net of payments, during the year December 31, 2024 and we made an aggregate of $117 million in income tax payments, net of refunds, during the year ended December 31, 2023.

NOTE 15—SHARE-BASED COMPENSATION
 
Our Amended and Restated 2020 Incentive Plan (the “2020 Plan”) is a broad-based incentive plan which allows for the issuance of stock options and stock appreciation rights and awards of bonus stock, phantom stock, restricted stock, restricted stock units and performance awards and other stock-based awards to employees, consultants and non-employee directors. The 2020 Plan provides for the issuance of 12.5 million shares of our common stock, of which we had 7.5 million shares available for future issuance as of December 31, 2025. Our outstanding awards as of December 31, 2025 primarily consisted of restricted stock units (“RSUs”) and performance stock units (“PSUs”). Other outstanding awards were not material to our Consolidated Financial Statements.

Restricted Stock Units

RSUs are stock awards that contain a graded vesting period of up to three years and, with the exception of awards to certain officers which contain a cash settlement option, as described in Liability-Classified Awards below, will settle in stock upon vesting subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions.

Performance Stock Units

PSUs provide for cliff vesting after a period of approximately three years with payouts dependent upon the achievement of metrics compared to pre-established performance targets over the defined performance period, including a performance condition consisting of cumulative distributable cash flow per share, and in certain circumstances, a market condition consisting of absolute total shareholder return (“ATSR”) of our common stock. All PSUs will settle in stock, with the exception of awards to certain officers which contain cash settlement features, either as granted or modified, as described in Liability-Classified Awards below.

Compensation cost attributed to the performance metric will vary due to changing estimates of units to be earned, based on expected achievement of the performance metric. The number of units that may be earned at the end of the vesting period ranges from 0% up to 300% of the target award amount.

Liability-Classified Awards

RSUs and PSUs granted to certain officers may be, as granted or modified, settled in cash in lieu of shares at the option of the officer following approval by the Compensation Committee, in order to limit the dilution from equity grants consistent with our share repurchase program under our long-term capital allocation plan, provided that we have sufficient liquidity to do so and the officers maintain certain stock ownership requirements. Except for those awards which contain a cash settlement option, PSUs granted to certain officers contain a cash settlement cap of $3 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
During the years ended December 31, 2025, 2024 and 2023, we paid $108 million, $109 million and $84 million, respectively, in cash upon vesting of the liability-classified awards.

Total share-based compensation costs, net of forfeitures, consisted of the following (in millions):
Year Ended December 31,
202520242023
Share-based compensation costs before income taxes:
Equity awards$121 $121 $100 
Liability awards48 101 155 
Total share-based compensation169 222 255 
Capitalized share-based compensation(8)(7)(5)
Total share-based compensation expense before income taxes$161 $215 $250 
Tax benefit associated with share-based compensation costs$44 $46 $54 
    
The table below provides a summary of activity related to our RSUs and PSUs (in millions, except for per unit information):
Restricted Stock UnitsPerformance Stock Units
Equity AwardsLiability AwardsEquity AwardsLiability Awards
 UnitsWeighted Average Grant Date Fair Value Per UnitUnitsWeighted Average Grant Date Fair Value Per UnitUnitsWeighted Average Grant Date Fair Value Per UnitUnitsWeighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2025
1.3 $149.52 0.2 $214.87 0.4 $153.07 0.5 $298.22 
Granted (1)0.6 220.62 0.0 194.39 0.1 246.04 — — 
Incremental units achieved (2)— — — — 0.1 171.01 — — 
Forfeited(0.1)183.41 — — — — — — 
Reclassifications (3)0.0 156.26 0.0 200.77 (0.2)176.25 0.2 226.72 
Vested (4)(0.7)143.97 (0.1)223.29 (0.1)115.84 (0.3)314.57 
Non-vested at December 31, 2025
1.1 $189.87 0.1 $194.39 0.3 $188.17 0.4 $224.20 
(1)The Equity Awards column for PSUs includes 0.1 million PSUs granted in 2025 to certain officers containing a cash settlement cap of $3 million.
(2)Represents incremental units recognized as a result of final performance measures or changes in estimated measures. As of December 31, 2025, there were 0.1 million PSUs that would be issued if the maximum level of performance under the target awards amount is achieved.
(3)During the years ended December 31, 2025, 2024 and 2023, we recognized $5 million, $14 million and $86 million, respectively, in incremental expense as a result of significant modifications involving reclassification between equity awards and liability awards, attributable to six, seven and six employees, respectively.
(4)The total fair value of RSUs and PSUs vested was $175 million and $107 million, respectively, for the year ended December 31, 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The table below provides the assumptions used in estimating the fair value of unvested awards containing market conditions as of the end of the respective periods, and for which the performance period had not yet ended:
Year Ended December 31,
202520242023
Fair value assumptions:
Dividend yield (1)— %— %— %
Expected volatility (2)(3)
26.5% - 30.1%
21.5% - 24.3%
27.5% - 32.7%
Weighted average expected volatility28.5 %22.9 %29.9 %
Risk-free interest rate (2)
3.5%
4.2% - 4.3%
4.2% - 4.8%
Weighted average expected remaining term, in years1.41.51.5
(1)The performance stock units are entitled to dividend equivalents during the performance period. Therefore, when calculating simulated returns, we applied an annual dividend yield of zero percent.
(2)Represents the range associated with individual vesting years. As of December 31, 2025, the risk-free interest rate is consistent across the individual vesting years and as such, no range is presented.
(3)The expected volatility is based on historical and implied volatilities of our common stock price.

The total unrecognized compensation cost at December 31, 2025 relating to non-vested share-based compensation arrangements was $168 million, which is expected to be recognized over a weighted average period of 1.4 years.

NOTE 16—EMPLOYEE BENEFIT PLAN

We have a defined contribution plan (“401(k) Plan”) which allows eligible employees to contribute up to 75% of their compensation up to the Internal Revenue Service maximum. We match each employee’s deferrals (contributions) up to 6% of compensation and may make additional contributions at our discretion. Employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $20 million, $18 million and $17 million for the years ended December 31, 2025, 2024 and 2023, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

NOTE 17—NET INCOME PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

We utilize the two-class method for computing earnings per share, which requires an allocation of earnings as if all earnings were distributed during the period to the common stockholders and participating securities. The redeemable NCI held by a third party in one of our consolidated VIEs is considered participating because, under certain circumstances, it is redeemable for cash at a return. Therefore, the accretion of the redeemable NCI to its redemption value, net of tax, which is recognized as a deemed dividend within retained earnings, is deducted from net income in computing net income per share attributable to common stockholders. In January 2026, we redeemed the remaining redeemable NCI in our consolidated VIE that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located immediately proximal to the Corpus Christi LNG Terminal, at a price that approximated our carrying value.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table provides a reconciliation of net income attributable to common stockholders and basic and diluted weighted average common shares outstanding (in millions, except per share data):
Year Ended December 31,
202520242023
Net income attributable to Cheniere$5,330 $3,252 $9,881 
Less: accretion of redeemable NCI, net of tax
15 — — 
Net income attributable to common stockholders$5,315 $3,252 $9,881 
Weighted average common shares outstanding:
Basic219.7 228.4 241.0 
Dilutive unvested stock0.6 0.7 1.6 
Diluted220.3 229.1 242.6 
Net income per share attributable to common stockholders—basic (1)
$24.19 $14.24 $40.99 
Net income per share attributable to common stockholders—diluted (1)
$24.13 $14.20 $40.72 
(1)Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.

NOTE 18—SHARE REPURCHASE PROGRAMS

The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):
Year Ended December 31,
202520242023
Total shares repurchased12.14 13.75 9.54 
Weighted average price paid per share$221.55 $163.72 $155.50 
Total cost of repurchases (1)$2,690 $2,251 $1,484 
(1)Amount excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.

As of December 31, 2025, we had approximately $1.2 billion remaining under our share repurchase program. Subsequently, in February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. Under the share repurchase authorization, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the Securities and Exchange Commission and other applicable legal requirements. The timing and amount of any shares of Cheniere’s common stock that are repurchased under the share repurchase authorization will be determined by Cheniere’s management based on market conditions and other factors. The share repurchase authorization does not obligate Cheniere to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at Cheniere’s discretion.

NOTE 19—COMMITMENTS AND CONTINGENCIES

Commitments
 
We have various future contractual commitments which do not meet the definition of a liability as of December 31, 2025 and thus are not recognized as liabilities in our Consolidated Financial Statements. Executed contracts containing such future commitments include agreements for capital expenditures, the use of LNG vessels contracted for future delivery, natural gas transportation and storage services, goods and services necessary to operate our Liquefaction Projects and letters of credit.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
CCL has contractual commitments under lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project. The total contract price of the EPC contracts, inclusive of amounts incurred under change orders, for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project were approximately $6.0 billion and $2.9 billion, respectively, of which we had remaining obligations of approximately $0.7 billion and $1.6 billion, respectively, as of December 31, 2025.

Environmental and Regulatory Matters

Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

Legal Proceedings

We are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material impact on our operating results, financial position or cash flows.

NOTE 20—SEGMENT INFORMATION AND CUSTOMER CONCENTRATION
 
We have determined that we operate as a single operating and reportable segment. Our executive team is organized by function, rather than legal entity or discrete financial data oversight, with no business component managers reporting to the chief operating decision maker (“CODM”), who is our president and chief executive officer. The CODM regularly analyzes financial and operational data on a single basis of segmentation at the consolidated level, consistent with our integrated service offering, in order to allocate resources and assess performance.

The measure of profit and loss regularly provided to the CODM that is most consistent with GAAP is net income attributable to Cheniere, as presented in our Consolidated Statements of Operations. This measure contributes to the CODM’s assessment of performance and resource allocation, which includes monitoring of budget versus actual results, establishing compensation and deciding on capital allocation priorities. Significant expenses regularly provided to the CODM, and included in the measure of profit and loss, are cost of sales, operating and maintenance expense and selling, general and administrative expense, as reported in our Consolidated Statements of Operations. Also provided regularly to the CODM are changes in the fair value of our derivative instruments, which are inclusive of significant noncash items, which were $3.6 billion, $1.3 billion and $8.0 billion in gains for the years ended December 31, 2025, 2024 and 2023. Interest income, which is included in interest and dividend income on our Consolidated Statements of Operations, was $102 million, $188 million and $206 million for the years ended December 31, 2025, 2024 and 2023.

The measure of segment assets is reported on our Consolidated Balance Sheets as total assets. Substantially all of our tangible long-lived assets, which consist of property, plant and equipment, are located in the U.S. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

For the years ended December 31, 2025, 2024 and 2023, we had no customers with revenues that were 10% or more of total revenues from contracts with external customers. We had one customer with a balance of 10% or more of trade receivables and contract assets, both net of current expected credit losses, representing 15% and 21% of total trade receivables and contract assets, both net of current expected credit losses, as of December 31, 2025 and 2024. Customers under common control are considered to be a single customer.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
The following table shows total revenues from contracts with external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues to the country in which the party to the applicable agreement has its principal place of business, with foreign countries that individually accounted for 10% or more of total revenues from contracts with external customers shown separately from the remaining countries. Revenues attributed to foreign countries exclude certain sales and other operating revenues for which attribution to a specific country is not practicable.
Total Revenues from Contracts with External Customers
Year Ended December 31,
202520242023
U.S.$3,664 $2,792 $3,012 
Singapore2,093 1,907 3,305 
United Kingdom1,639 1,257 2,823 
Other countries12,068 9,458 10,641 
Total$19,464 $15,414 $19,781 

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of substantive cash flow information (in millions): 
Year Ended December 31,
202520242023
Cash paid during the period for interest on debt, net of amounts capitalized$844 $1,075 $1,032 
Non-cash investing activities:
Unpaid purchases of property, plant and equipment (1)(2)261 256 204 
Conveyance of other non-current assets to equity method investee in exchange for infrastructure support— 34 30 
Non-cash financing activities (1):
Unpaid excise tax on stock repurchased during the year26 21 13 
Unpaid repurchase of common stock— — 10 
Unpaid dividends— — 3 
(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.
(2)Net of proceeds not yet collected from commissioning sales of LNG of $13 million, zero and zero, respectively.
See Note 11—Leases and Note 14—Income Taxes for supplemental cash flow information related to our leases and income taxes, respectively.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.

ITEM 9A.    CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2025, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
 
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Management’s Report on Internal Control Over Financial Reporting
 
Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements and is incorporated herein by reference.

ITEM 9B.    OTHER INFORMATION

Rule 10-b5-1 Trading Arrangements

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending December 31, 2025, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III
 
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 13 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2025.

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185.

The remaining information required by this Item is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2025.
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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    Financial Statements, Schedules and Exhibits

(1)    Financial Statements—Cheniere Energy, Inc. and Subsidiaries:


(2)     Financial Statement Schedules:

All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included in the consolidated financial statements and accompanying notes included in this Form 10-K.

(3)    Exhibits:

Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:

•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;

•may apply standards of materiality that differ from those of a reasonable investor; and

•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.

Exhibit No.Incorporated by Reference (1)
DescriptionEntityFormExhibitFiling Date
2.1
CQP
8-K10.28/9/2012
3.1Cheniere10-Q3.18/10/2004
3.2Cheniere8-K3.12/8/2005
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Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
3.3
Cheniere
(SEC File No. 333-160017)
S-84.36/16/2009
3.4Cheniere8-K3.16/7/2012
3.5Cheniere8-K3.12/5/2013
3.6
Cheniere
8-K
3.1
5/24/2024
3.7Cheniere8-K3.19/3/2024
4.1
Cheniere
(SEC File No. 333-10905)
S-14.18/27/1996
4.2
CQP
8-K4.12/4/2013
4.3
CQP
8-K4.1.14/16/2013
4.4
CQP
8-K4.1.24/16/2013
4.5
CQP
8-K4.111/25/2013
4.6
CQP
8-K4.15/22/2014
4.7
CQP8-K4.25/22/2014
4.8CQP8-K4.13/3/2015
4.9CQP8-K4.16/14/2016
4.10CQP8-K4.16/14/2016
4.11CQP8-K4.19/23/2016
4.12CQP8-K4.29/23/2016
4.13CQP8-K4.29/23/2016
4.14CQP8-K4.13/6/2017
4.15CQP8-K4.13/6/2017
4.16SPL8-K4.15/8/2020
4.17SPL8-K4.15/8/2020
4.18SPL8-K4.111/29/2022
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Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
4.19SPL8-K4.111/29/2022
4.20
CQP
8-K4.12/27/2017
4.21
CQP
8-K4.12/27/2017
4.22
Cheniere
10-K
4.242/24/2022
4.23
Cheniere
10-K
4.242/24/2022
4.24
Cheniere
10-K
4.262/24/2022
4.25
Cheniere
10-K
4.262/24/2022
4.26
Cheniere
10-K
4.282/24/2022
4.27
Cheniere
10-K
4.282/24/2022
4.28
Cheniere
10-K
4.302/24/2022
4.29
Cheniere
10-K
4.302/24/2022
4.30
Cheniere
10-K
4.322/24/2022
4.31
Cheniere
10-K
4.322/24/2022
4.32Cheniere8-K4.19/22/2020
4.33Cheniere8-K4.29/22/2020
4.34Cheniere8-K4.29/22/2020
4.35
Cheniere
8-K
4.1
3/19/2024
4.36
Cheniere
8-K
4.2
3/19/2024
4.37
Cheniere
8-K
4.2
3/19/2024
4.38Cheniere8-K4.15/18/2016
4.39Cheniere8-K4.112/9/2016
4.40CCH8-K4.15/19/2017
4.41CCH8-K4.15/19/2017
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Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
4.42CCH8-K4.19/12/2019
4.43CCH8-K4.111/13/2019
4.44CCH8-K4.111/13/2019
4.45CCH8-K4.18/24/2021
4.46CCH8-K4.18/24/2021
4.47CCH8-K4.18/21/2020
4.48CCH8-K4.18/21/2020
4.49CCH8-K4.19/30/2019
4.50CCH8-K4.19/30/2019
4.51CCH8-K4.110/18/2019
4.52CCH8-K4.110/18/2019
4.53
CQP
8-K4.19/18/2017
4.54
CQP
8-K4.29/18/2017
4.55
CQP
8-K4.19/12/2018
4.56
CQP
8-K4.19/12/2019
4.57CQP8-K4.19/12/2019
4.58Cheniere10-Q4.411/6/2020
4.59CQP8-K4.13/11/2021
4.60CQP8-K4.13/11/2021
4.61CQP8-K4.19/27/2021
103
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
4.62CQP8-K4.19/27/2021
4.63CQP8-K4.110/1/2021
4.64
CQP
8-K
4.1
6/21/2023
4.65
CQP
8-K
4.1
6/21/2023
4.66
CQP
8-K
4.1
5/22/2024
4.67
CQP
8-K
4.1
5/22/2024
4.68
CQP
8-K
4.1
7/10/2025
4.69
CQP
8-K
4.1
7/10/2025
4.70
Cheniere
10-K
4.69
2/20/2025
10.1†
Cheniere (SEC No. 333-238261)
S-84.95/14/2020
10.2†
Cheniere
8-K
10.1
5/24/2024
10.3†Cheniere10-Q10.18/5/2021
10.4†
Cheniere
10-K
10.5
2/2/2024
10.5†Cheniere10-K10.82/22/2024
10.6†Cheniere10-K10.92/22/2024
10.7†
Cheniere
10-K
10.462/24/2022
10.8†
Cheniere
10-K
10.472/24/2022
10.9†Cheniere8-K10.15/12/2016
10.10†Cheniere8-K10.18/15/2019
10.11†Cheniere8-K10.18/13/2021
10.12†Cheniere10-K
10.15
2/22/2024
10.13†Cheniere8-K10.25/20/2020
10.14†Cheniere8-K10.15/20/2020
104
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.15
SPL
(SEC File No. 333-273238)
S-4
10.46
7/13/2023
10.16
SPL
(SEC File No. 333-273238)
S-4
10.44
7/13/2023
10.17SPL8-K10.33/23/2020
10.18Cheniere8-K10.16/22/2022
10.19
Cheniere
10-Q
10.4
8/8/2024
10.20Cheniere8-K10.36/22/2022
10.21
Cheniere
10-Q
10.5
8/8/2024
10.22Cheniere8-K10.46/22/2022
10.23
Cheniere
10-Q
10.6
8/8/2024
10.24Cheniere8-K10.45/24/2018
10.25Cheniere8-K10.55/24/2018
10.26Cheniere8-K10.26/22/2022
10.27Cheniere10-Q10.78/8/2024
10.28Cheniere10-Q10.38/7/2025
10.29Cheniere8-K10.16/19/2020
105
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.30
Cheniere
10-Q
10.4
8/3/2023
10.31Cheniere10-Q10.15/4/2022
10.32Cheniere10-Q10.78/4/2022
10.33Cheniere10-Q10.211/3/2022
10.34
Cheniere
10-K
10.96
2/23/2023
106
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.35
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction Stage III, LLC and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Chart License Fee Provisional Sum Closure, dated September 16, 2022, (ii) the Change Order CO-00013 HRU Nozzles and Block Headers, dated September 21, 2022, (iii) the Change Order CO-00014 Addition of Nitrogen Receiver, dated December 13, 2022, (iv) the Change Order CO-00015 Package 6 Feed Gas Pipeline Interfaces, dated December 14, 2022, (v) the Change Order CO-00016 Old Sherwin Building Security, dated November 23, 2022, (vi) the Change Order CO-00017 Remote Monitoring Diagnostic for Mixed Refrigerant (MR) Compressors, dated December 14, 2022, (vii) the Change Order CO-00018 EFG Package #1, dated January 9, 2023, (viii) the Change Order CO-00019 Q3 2022 Commodity Price Rise and Fall (ATT MM), dated January 17, 2023, (ix) the Change Order CO-00020 ICSS Vendor Selection and EPC Warranty (Yokogawa), dated September 21, 2022 and (x) the Change Order CO-00021 Laydown Development Package, dated February 6, 2023 (Portions of this exhibit have been omitted.)
Cheniere
10-Q
10.2
5/2/2023
10.36
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction, LLC and Bechtel Energy, Inc.: (i) the Change Order CO-00022 Refrigerant Storage Packages 1 and 2, dated February 13, 2023, (ii) the Change Order CO-00023 EFG Package #2, dated February 21, 2023, (iii) the Change Order CO-00024 Defrost Improvements (Cold Box), dated February 23, 2023, (iv) the Change Order CO-00025 Miscellaneous Design Improvements, dated February 23, 2023, (v) the Change Order CO-00026 EFG Package #3, dated February 23, 2023, (vi) the Change Order CO-00027 Addition of 86 Lockout Relay on Transformers, dated February 14, 2023, (vii) the Change Order CO-00028 Additional Duct Banks, dated September 15, 2022, (viii) the Change Order CO-00029 2022 FERC Support Hours Interim Adjustment, dated March 13, 2023, (ix) the Change Order CO-00030 Drainage Blanket (A Street), dated April 6, 2023, (x) the Change Order CO-00031 Refrigerant Storage Interface Package #3, dated April 7, 2023, (xi) the Change Order CO-00032 Q4 2022 Commodity Price Rise and Fall (ATT MM), dated April 24, 2023, (xii) the Change Order CO-00033 Lift Owner-Provided Dewar System (Nitrogen Receiver Facility), dated March 1, 2022, (xiii) the Change Order CO-00034 HAZOP Package #1 - Addition of Flame Arrestors for Oil Mist Eliminator Vent, dated April 25, 2023 and (xiv) the Change Order CO-00035 EFG Package #4 (Water Pipeline Pipe Bridge), dated May 19, 2023 (Portions of this exhibit have been omitted.)
Cheniere
10-Q
10.1
8/3/2023
10.37
Cheniere
10-Q
10.2
11/2/2023
107
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.38
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00040 Q1 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (ii) the Change Order CO-00041 Q2 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (iii) the Change Order CO-00042 HAZOP Package #2 – Additional IPL (Pressure Transmitter Across the Strainer), dated July 5, 2023, (iv) the Change Order CO-00043 Total Condensate Flowmeter on Three (3) Inch Condensate Line, dated August 31, 2023, (v) the Change Order CO-00044 FERC Package #1 ISA 84 (Accommodation for Two Hundred and Fifty (250) Fire and Gas Detectors), dated August 31, 2023, (vi) the Change Order CO-00045 Increase LNG Rundown Line Check Valve Bypass Size to Six (6) Inches, dated August 31, 2023, (vii) the Change Order CO-00046 Add Manual Bypass Valves Around 31XV-13071, dated September 13, 2023, (viii) the Change Order CO-00047 Relocate Existing 16” Process Water Line and Provide Tie-In, dated September 8, 2023, (ix) the Change Order CO-00048 Future HRU Bypass Tie-In and Thermowell Updates, dated September 12, 2023, (x) the Change Order CO-00049 Butterfly Valves for Flare Drums, dated September 5, 2023, (xi) the Change Order CO-00050 Condensate Shroud on Condensate Rundown Line (Blue Engineering Report), dated September 12, 2023, (xii) the Change Order CO-00051 EFG Package #5 (138KV Feeder Cable), dated September 8, 2023, (xiii) the Change Order CO-00052 Defect Correction Period for Cementitious Fireproofing, dated August 7, 2023, (xiv) the Change Order CO-00053 Chart Transition Joint Spares, dated October 5, 2023, (xv) the Change Order CO-00054 CCL Tank(s) “A” and “C” Tie-In Study & Long Lead Item Purchases, dated September 19, 2023, (xvi) the Change Order CO-00055 FERC Package #2 Firewater Layout, dated September 13, 2023, (xvii) the Change Order CO-00056 HAZOP Package #3 – Stainless Steel C And D Pass Piping / Two Temperature Transmitters per Train, dated February 14, 2023, (xviii) the Change Order CO-00057 HAZOP Package #4 (“Phase Two Items”), dated October 10, 2023, (xix) the Change Order CO-00058 E-HAZOP Package #1 (“LV MCC Ride Through”), dated September 8, 2023, (xx) the Change Order CO-00059 Level Transmitter on Stand Pipe Inside Liquefaction Cold Boxes, dated October 13, 2023, (xxi) the Change Order CO-00060 Small Spill Containment (Additional Curbs), dated July 5, 2023, (xxii) the Change Order CO-00061 Remote Input/Output (RIO) Junction Box Grounding, dated October 10, 2023, (xxiii) the Change Order CO-00062 Geomembrane Liner and Geocell for Laydown 6 Channel, dated August 31, 2023, (xxiv) the Change Order CO-00063 Phased Surfacing of Permanent Plant Roads, dated August 7, 2023, (xxv) the Change Order CO-00064 Provisional Sum Interim Adjustment - Schedule KK-1 12-Month COVID Countermeasures, dated July 24, 2023, (xxvi) the Change Order CO-00065 Modification to FTZ Zone Site (Exhibit A of Attachment LL), dated August 3, 2023, (xxvii) the Change Order CO-00066 Attachment B (Contract Deliverables), dated June 2, 2023, (xxviii) the Change Order CO-00067 Sheet Pile Joint Sealing 310Q02 Sump, dated October 5, 2023, (xxix) the Change Order CO-00068 E-HAZOP Package #2 (“Phase One Items”), dated October 19, 2023, (xxx) the Change Order CO-00069 Package 6 Feed Gas Pipeline and Pig Receiver DMM, dated August 3, 2023, (xxxi) the Change Order CO-00070 Dry Flare Knockout Drum Spill Pad Drain Specification Change, dated October 5, 2023, (xxxii) the Change Order CO-00071 Viewing Platform Piles, dated October 18, 2023, (xxxiii) the Change Order CO-00072 Site Plan Update Package #1 – Re-Route Contractor’s Utility Water & Nitrogen Pipelines and Provide Power & Fiber Cables To Nitrogen Tie-In Point, dated November 2, 2023, (Portions of this exhibit have been omitted.)
Cheniere
10-K
10.57
2/22/2024
108
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.39
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00073 Amendment to Add Provisional Sums for the Performance and Attendance Bonus (PAB) and Saturday Work Shift Program, dated November 6, 2023, (ii) the Change Order CO-00074 Q3 2023 Commodity Price Rise and Fall Adjustment (Final Attachment MM Adjustment), dated November 6, 2023, (iii) the Change Order CO-00075 Surcharge Fill Material Transportation, dated October 11, 2023, (iv) the Change Order CO-00076 FERC Package #3 Firewall Layout (310R18), dated November 6, 2023, (v) the Change Order CO-00077 Site Plan Update Package #2 - Re-route Heavy Haul Road, dated November 2, 2023, (vi) the Change Order CO-00078 Firewater Loop Interconnect with CCL Stage 1 and CCL Stage 2, dated December 6, 2023, (vii) the Change Order CO-00079 Refrigerant Loading Manifold Design Changes, dated December 6, 2023, (viii) the Change Order CO-00080 CCL Tank(s) “A” and “C” Tie-in Long Lead Item Purchases Package #2, dated January 26, 2024, (ix) the Change Order CO-00081 CCL Tank(s) “A” and “C” Tie-in Bridging Engineering (Through 29-Mar-2024), dated February 8, 2024, (x) the Change Order CO-00082 ISA 84 Owner Requested Changes, dated January 24, 2024, (xi) the Change Order CO-00083 HAZOP Package #5 (“Phase Three Items”), dated October 19, 2023, (xii) the Change Order CO-00084 CCL Tank(s) “A” and “C” Long-Lead Item Purchases Package #3, dated March 4, 2024, (xiii) the Change Order CO-00085 Site Plan Update Package #3 - Fencing, dated January 17, 2024 (Portions of this exhibit have been omitted.)
Cheniere10-Q
10.2
5/3/2024
10.40Cheniere10-Q
10.1
8/8/2024
10.41Cheniere10-Q
10.2
10/31/2024
109
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.42
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00093 Local Temperature Indication at LNG Rundown Line, dated September 23, 2024, (ii) the Change Order CO-00094 Tie-In Connection for Future Isopentane Injection, dated October 21, 2024, (iii) the Change Order CO-00095 Flame Detection Coverage Package #1, dated October 21, 2024, (iv) the Change Order CO-00096 Metering Telemetry in GIS Substation, dated November 13, 2024, (v) the Change Order CO-00097 Sifting and Sorting Operations, dated October 1, 2024, and (vi) the Change Order CO-000-98 Acceleration Program Provisional Sum, dated December 20, 2024 (Portions of this exhibit have been omitted.)
Cheniere
10-K
10.46
2/20/2025
10.43
Cheniere
10-Q10.15/8/2025
10.44
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-000100 HAZOP Provisional Sum Closure, dated August 24, 2024, (ii) the Change Order CO-00101 Hot Oil Spools and Heat Exchange Coating Specification, dated March 5, 2025, (iii) the Change Order CO-00102 Reconciliation (Tax) - Change Orders CO-00014 through CO-00061, dated February 2, 2024, (iv) the Change Order CO-00103 Lube Oil for Refrigeration Compressor, dated April 30, 2025, (v) the Change Order CO-00104 Miscellaneous Scope Revisions, dated March 13, 2025, (vi) the Change Order CO-00105 FERC and PHMSA (DOT) Support Hours (2024 Period), dated May 16, 2025, (vii) the Change Order CO-00106 Closure of Performance and Attendance Bonus (PAB) and Saturday Work Shift Program Provisional Sum, dated May 16, 2025, (viii) the Change Order CO-00107 P&ID Natives for Trains 1- 2 and OSBL Phase 1, dated May 16, 2025, (ix) the Change Order CO-00108 Stormwater Sampling Outfall 003 (Small Triangle Area), dated May 22, 2025, and (x) the Change Order CO-00109 Owner Request for Train 1 Refrigerant Staging (Standby Driver), dated May 22, 2025 (Portions of this exhibit have been omitted.)
Cheniere
10-Q10.18/7/2025
10.45
Cheniere
10-Q10.110/30/2025
110
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
10.46*
10.47
CQP
8-K10.111/21/2011
10.48
CQP
10-Q10.15/3/2013
10.49
SPL
(SEC File No. 333-215882)
S-410.32/3/2017
10.50Cheniere
10-Q
10.13
8/3/2023
10.51
CQP
8-K10.11/26/2012
10.52Cheniere
10-Q
10.10
8/3/2023
10.53Cheniere8-K10.16/2/2014
10.54Cheniere10-Q10.65/4/2018
10.55
Cheniere
10-Q
10.9
8/3/2023
10.56Cheniere10-Q10.711/6/2007
10.57
CQP
8-K10.18/6/2012
10.58
CQP
8-K3.12/21/2017
10.59
Cheniere Holdings
8-K10.312/18/2013
14.1*
19*
111
Table of Contents
Exhibit No.Incorporated by Reference (1)
Exhibit No.DescriptionEntityFormExhibitFiling Date
21.1*
23.1*
31.1*
31.2*
32.1**
32.2**
97*
101.INS*XBRL Instance Document
101.SCH*XBRL Taxonomy Extension Schema Document
101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document
104*Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
(1)
Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), CQP (SEC File No. 001-33366), Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (SEC File No. 001-36234), SPL (SEC File No. 333-192373), CCH (SEC File No. 333-215435) and SPLNG (SEC File No. 333-138916), as applicable, unless otherwise indicated.
*Filed herewith.
**Furnished herewith.
†Management contract or compensatory plan or arrangement.

ITEM 16.    FORM 10-K SUMMARY

None.

112
Table of Contents


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 

CHENIERE ENERGY, INC.
(Registrant)
  
By:/s/ Jack A. Fusco
Jack A. Fusco
President and Chief Executive Officer
(Principal Executive Officer)
Date:February 25, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ Jack A. FuscoPresident and Chief Executive Officer and Director (Principal Executive Officer)February 25, 2026
Jack A. Fusco
/s/ Zach DavisExecutive Vice President and Chief Financial Officer (Principal Financial Officer)February 25, 2026
Zach Davis
/s/ David SlackSenior Vice President and Chief Accounting Officer
(Principal Accounting Officer)		February 25, 2026
David Slack
/s/ G. Andrea BottaChairman of the BoardFebruary 25, 2026
G. Andrea Botta
/s/ Patricia K. CollawnDirectorFebruary 25, 2026
Patricia K. Collawn
/s/ Brian E. EdwardsDirectorFebruary 25, 2026
Brian E. Edwards
/s/ Denise GrayDirectorFebruary 25, 2026
Denise Gray
/s/ Lorraine MitchelmoreDirectorFebruary 25, 2026
Lorraine Mitchelmore
/s/ W. Benjamin MorelandDirectorFebruary 25, 2026
W. Benjamin Moreland
/s/ Donald F. Robillard, Jr.DirectorFebruary 25, 2026
Donald F. Robillard, Jr.
/s/ Matthew RunkleDirectorFebruary 25, 2026
Matthew Runkle
/s/ Neal A. ShearDirectorFebruary 25, 2026
Neal A. Shear
113
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

 

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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from to

Commission File Number 001-38497

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Talos Energy Inc.

(Exact name of Registrant as specified in its Charter)

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Delaware

82-3532642

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer
Identification No.)

333 Clay Street, Suite 3300

Houston, TX

77002

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code: (713) 328-3000

Securities registered pursuant to Section 12(b) of the Act:

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Title of Each Class

 

Trading Symbol(s)

 

Name of Each Exchange on Which Registered

Common Stock

 

TALO

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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Large accelerated filer

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Accelerated filer

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Non-accelerated filer

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Smaller reporting company

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Emerging growth company

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on the New York Stock Exchange on June 30, 2025, was $1,106,796,185.

The number of shares of registrant’s Common Stock outstanding as of February 17, 2026 was 168,514,683.

Portions of the registrant’s definitive proxy statement relating to the 2026 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

 

 

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GLOSSARY

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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SUMMARY RISK FACTORS

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PART I

 

Items 1 and 2.

Business and Properties

9

Item 1A.

Risk Factors

27

Item 1B.

Unresolved Staff Comments

43

Item 1C.

Cybersecurity

43

Item 3.

Legal Proceedings

44

Item 4.

Mine Safety Disclosures

45

 

PART II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities

46

Item 6.

[Reserved]

47

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

48

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

64

Item 8.

Financial Statements and Supplementary Data

65

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

65

Item 9A.

Controls and Procedures

65

Item 9B.

Other Information

66

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

66

 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

67

Item 11.

Executive Compensation

67

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

67

Item 13.

Certain Relationships and Related Transactions, and Director Independence

67

Item 14.

Principal Accountant Fees and Services

67

 

PART IV

 

Item 15.

Exhibits and Financial Statement Schedules

68

Item 16.

Form 10-K Summary

71

 

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GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.

Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

Boepd — Barrels of oil equivalent per day.

Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

CCS — Carbon capture and sequestration.

CO2 — Carbon dioxide.

Completion — The installation of permanent equipment for the production of oil or natural gas.

Deepwater — Water depths of more than 600 feet.

Developed acres — The number of acres that are allocated or assignable to producing wells or wells capable of production.

Dry well — A well that is an exploratory or development well that is not a productive well.

Field — An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

GAAP — Accounting principles generally accepted in the United States of America.

Gross acres or gross wells — The total acres or wells in which the Company owns a working interest.

MBbls — One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe — One thousand barrels of oil equivalent.

MBoepd — One thousand barrels of oil equivalent per day.

MBopd — One thousand barrels of oil per day.

Mcf — One thousand cubic feet of natural gas.

Mcfpd — One thousand cubic feet of natural gas per day.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units.

MMcf — One million cubic feet of natural gas.

MMcfpd — One million cubic feet of natural gas per day.

Net acres or net wells — The sum of the fractional working interests the Company owns in gross acres or gross wells.

NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX — The New York Mercantile Exchange.

NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

OPEC — Organization of Petroleum Exporting Countries.

Productive well — A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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Proved developed reserves — In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves — In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10 — The present value, discounted at 10% annually, of estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production costs, future development costs, and abandonment costs using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and future income tax expense or (ii) depreciation, depletion and amortization expense.

SEC — The U.S. Securities and Exchange Commission.

SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf — Water depths of up to 600 feet.

Standardized Measure — The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development costs, production costs, abandonment costs, and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.

Undeveloped acreage — Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K (this “Annual Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “potential,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include, but are not limited to, statements about:

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business strategy;
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estimated or recoverable resources and reserves;
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drilling prospects, inventories, projects and programs;
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our ability to replace the reserves that we produce through drilling, acquisitions, recompletions or enhanced recovery;
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financial strategy, borrowing base under our credit agreement, availability of financing sources and under our credit facility, liquidity position and capital required for our development program, acquisitions and other capital expenditures;
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realized oil and natural gas prices;
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changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements including such changes that may be implemented by the current or future administrations or foreign governments, and the impact of such policies on us, our customers and suppliers and the global economic environment;
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volatility in the political, legal and regulatory environments where we currently or in the future may operate;
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risks related to future mergers and acquisitions, including the risk that we may fail to realize the expected benefits of any such transaction;
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timing and amount of future production of oil, natural gas and NGLs, including a potential increase in OPEC oil supply and any related impact on global oil prices and domestic oil production;
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our hedging strategy and results;
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future drilling plans;
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availability of pipeline connections and other infrastructure on economic terms;
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competition, government regulations, including financial assurance requirements, and legislative and political developments;
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our ability to obtain permits and governmental approvals;
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pending legal, governmental or environmental matters;
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our marketing of oil, natural gas and NGLs;
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our integration of acquisitions and the anticipated post-acquisition performance of the Company;
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future leasehold or business acquisitions on desired terms;
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costs of developing, acquiring or abandoning properties;
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general economic conditions, including the impact of continued inflation and associated changes in monetary policy;
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political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage;
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credit markets;
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estimates of future income taxes;
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our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;
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our strategy, timeline and results with respect to our investment in the Zama asset;
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uncertainty regarding our future operating results and our future revenues and expenses;
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anticipated capital efficiency, margin enhancement and organizational improvements and additional cash flow;
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our ability to obtain surety bonds on commercially reasonable terms; expected collateral requirements under existing or future surety agreements; market factors impacting the availability of surety bonds;
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the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, surety bonds and other secured debt;
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impact of new accounting pronouncements on earnings in future periods; and
•
plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”) to set and maintain oil production levels and the impact of any such actions; foreign wars and conflicts, including the lack of a resolution to the war in Ukraine and ongoing hostilities in Israel and the Middle East and recent U.S. intervention in Venezuela, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of necessary infrastructure, transportation and storage capacity as a result of oversupply, government and regulations; political risks, including a global trade war or the impact of any prolonged federal government shutdown or lapse in federal appropriations that could disrupt our operations and future drilling plans and opportunities; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats and incidents; elevated inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current and future discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes, including the impact of financial assurance requirements; changes in U.S. trade and labor policies, including the imposition of increased tariffs and the resulting consequences; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in Part I, Item 1A. Risk Factors which are included herein.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions used by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

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SUMMARY RISK FACTORS

Risks Related to our Business and the Oil and Natural Gas Industry

•
Oil and natural gas prices are volatile and prolonged price declines could materially adversely affect our business, financial condition, results of operations, cash flows, access to capital, and our ability to replace and grow future production.
•
If we are unable to replace oil and natural gas reserves, we may not be able to sustain or grow our business.
•
Future exploration and drilling results are uncertain and involve substantial costs.
•
Our current operations are primarily concentrated in a single geographic region, making us vulnerable to regional risks.
•
Global geopolitical tensions may increase volatility in oil, gas and NGL prices and could adversely affect our business.
•
Our actual recovery of reserves may differ substantially from our proved reserve estimates.
•
Our future asset retirement obligations, including plugging and abandonment expenditures and decommissioning costs, are difficult to predict, may vary significantly from period to period and could materially adversely affect our current and future financial results.
•
We risk losing leases if we cannot drill before such leases expire.
•
We depend on infrastructure to market and deliver our production.
•
Inflation and interest rate changes could increase our costs.
•
We may not be able to obtain sufficient surety bonds on reasonably acceptable terms to conduct our business.
•
Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.
•
We have limited control over the activities on properties we do not operate.
•
Hedging transactions may limit our potential gains and expose us to other risks.
•
Compliance with environmental laws, including legal requirements related to marine life and endangered and threatened species, could increase our costs and limit operations.
•
Regulatory changes could restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to leases, which could have a material adverse effect on our business, financial condition or results of operations.
•
Production shut-ins could increase costs and reduce future production.
•
Severe weather or public health events could disrupt production and reduce revenues.
•
We are not insured against all of the operating risks to which our business is exposed.
•
Our actual production could differ materially from our forecasts.
•
Our strategy emphasizes Deepwater exploration and development, which involves significantly higher operational and financial risks than operations in shallower waters. Deepwater activities in the Gulf of America are complex, capital‑intensive, and subject to a wide range of uncertainties.
•
Intense industry competition could limit our growth and increase costs.
•
The loss of a significant customer could materially reduce our revenue and materially adversely affect our business.
•
We rely on skilled and experienced personnel, and shortages in such personnel, higher labor costs or the loss of key management could adversely affect our ability to operate.
•
We have various contractual commitments. Our failure to satisfy these commitments could adversely affect our results of operations and financial position.
•
Changes in U.S. trade policy, including tariffs or other restrictions, could increase costs and adversely affect our business.
•
We may not realize expected benefits from future acquisitions, and integration challenges could harm our business.
•
Acquisitions and current assets expose us to potentially significant liabilities, including abandonment obligations.
•
Litigation outcomes could materially affect our financial condition.
•
Lower oil and natural gas prices and other factors have resulted in, and may in the future result in additional, ceiling test impairments and other impairments of our asset carrying values.

Risks Related to our Capital Structure and Ownership of our Common Stock

•
Our debt level and related covenants in our current or future credit agreement and indentures could restrict our operations, and failure to comply with the covenants could result in accelerated payment obligations.
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•
The Carlos Slim family’s significant ownership and voting power may create conflicts of interest and influence shareholder votes and major strategic decisions.
•
A financial crisis or disruption in credit markets could limit our access to funding and adversely impact our ability to do business.
•
We require substantial capital to fund our operations and replace our production and may not be able to obtain financing on acceptable terms.
•
As a holding company, we depend on distributions from Talos Production Inc. and our subsidiaries to meet our obligations.
•
Future sales, or the perception of future sales, of our stock could lower our share price and dilute the holdings of our existing stockholders.
•
Stockholder activism could disrupt our business and harm our stock price.

 

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Part I

Items 1 and 2. Business and Properties

Overview

As used in this Annual Report and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to Talos Energy Inc. and its consolidated subsidiaries.

We are a publicly traded Delaware corporation and our common stock is listed on the New York Stock Exchange (the “NYSE”) under the symbol “TALO.”

We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and reserve recovery, safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.

Business Strategy

In June 2025, we announced our enhanced corporate strategy to position us as a leading pure-play offshore exploration and production company. Our strategy includes the following three pillars:

•
Improve the business every day. Target increased annualized free cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements.
•
Grow production and profitability. Invest in high-margin organic projects, complemented by disciplined, accretive bolt-on acquisitions in Deepwater basins, which will enhance production and profitability.
•
Build a long-lived, scaled portfolio. Participate in greenfield developments, explore for large resource potential, acquire and develop projects with significant reserves, and evaluate opportunities within the Gulf of America and other conventional basins. A scaled portfolio will provide us with significant growth potential and ultimately the ability to generate long-term consistent free cash flow.

This strategy is underpinned by a disciplined capital allocation framework which prioritizes investing in projects expected to generate robust returns through commodity cycles, returning cash to shareholders, maintaining a strong balance sheet, and growing through selective opportunities.

Properties

U.S. Gulf of America

Our activities are primarily concentrated in the Deepwater area but we also have operations on the Shelf and Gulf Coast. The Deepwater region in the Central U.S. Gulf of America remains a vital basin and a core focus area for our exploration, development and operational activities. This region has a history of prolific production and ongoing exploration success, with further opportunities to unlock additional resources. We concentrate in areas characterized by clearly defined infrastructure, well-known production history and geological well control, which reduces operational and investment risk.

The following table sets forth a summary of certain key 2025 information regarding our areas of operation in the U.S.:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + + + + +

 

Estimated Proved Reserves

 

 

 

 

 

 

MBoe

 

% Oil

 

% Natural Gas

 

% NGLs

 

% Proved Developed

 

Net Production (MBoe)

 

% Operated

 

Deepwater

 

159,697

 

 

78

 %

 

15

 %

 

7

 %

 

78

 %

 

31,047

 

 

81

 %

Shelf & Gulf Coast

 

14,996

 

 

35

 %

 

52

 %

 

13

 %

 

85

 %

 

3,487

 

 

76

 %

Total United States

 

174,693

 

 

75

 %

 

19

 %

 

6

 %

 

78

 %

 

34,534

 

 

81

 %

 

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As of December 31, 2025, our acreage, seismic and key facilities and fields in the U.S. are summarized in the illustration below:

img251216048_1.jpg

Mexico

Our area of focus in Mexico is the Block 7, Zama Unit Area segment located within the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Tabasco state. In 2015, a Talos-led consortium (the “Block 7 Consortium”) was awarded a production sharing contract (“PSC”) covering Block 7 with a term of thirty years, extendable for two additional five-year periods. Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) was named operator of Block 7. On March 22, 2022, Block 7 was unitized with a neighboring block operated by Petróleos Mexicanos (“PEMEX”).

Talos Mexico, the Mexican affiliates of Harbour Energy (“Harbour Energy”), and PEMEX hold gross interests of 17.35%, 32.22%, and 50.43%, respectively, in the unitized Zama Field. On December 19, 2025, the Mexican Ministry of Energy (“SENER”) approved the transfer of Block 7 operatorship from Talos Mexico to Harbour Energy. In addition, on December 29, 2025, SENER approved the transfer of operatorship of the Zama Field from PEMEX to Harbour Energy.

In September 2023, we closed the sale of a 49.9% equity stake in Talos Mexico to Zamajal, S.A. de C.V. (“Zamajal”), majority-owned by Grupo Carso, S.A.B. de C.V. (“Carso”) (the “2023 Mexico Divestiture”). In December 2024, we entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal (the “Incremental Mexico Equity Sale”). While we anticipate the Incremental Mexico Equity Sale will close before the end of the second quarter of 2026, there can be no assurance that all of the conditions to closing, including obtaining necessary regulatory approvals, will be satisfied. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information on the 2023 Mexico Divestiture; Note 7 — Equity Method Investments for additional information on both Talos Mexico and the Incremental Mexico Equity Sale; and Note 14 — Related Party Transactions for additional information on Carso.

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Summary of Reserves

The following table summarizes our estimated proved reserves which are all located in the United States:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + +

 

Oil
(MBbls)

 

Natural Gas
(MMcf)

 

NGLs
(MBbls)

 

MBoe

 

Standardized
Measure
(in thousands)

 

PV -10
(in thousands)

 

Consolidated Entities:

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2025

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing

 

78,537

 

 

103,638

 

 

7,092

 

 

102,902

 

 

 

$

2,419,008

 

Proved developed non-producing

 

22,494

 

 

52,782

 

 

2,552

 

 

33,843

 

 

 

 

438,503

 

Total proved developed

 

101,031

 

 

156,420

 

 

9,644

 

 

136,745

 

 

 

 

2,857,511

 

Proved undeveloped

 

29,595

 

 

38,180

 

 

1,990

 

 

37,948

 

 

 

 

331,526

 

Total proved

 

130,626

 

 

194,600

 

 

11,634

 

 

174,693

 

$

2,804,857

 

$

3,189,037

 

December 31, 2024

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing

 

82,687

 

 

108,041

 

 

8,279

 

 

108,973

 

 

 

$

2,875,948

 

Proved developed non-producing

 

25,792

 

 

67,098

 

 

4,454

 

 

41,429

 

 

 

 

715,006

 

Total proved developed

 

108,479

 

 

175,139

 

 

12,733

 

 

150,402

 

 

 

 

3,590,954

 

Proved undeveloped

 

34,569

 

 

42,835

 

 

2,132

 

 

43,840

 

 

 

 

609,770

 

Total proved

 

143,048

 

 

217,974

 

 

14,865

 

 

194,242

 

$

3,564,204

 

$

4,200,724

 

December 31, 2023

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed producing

 

75,132

 

 

90,279

 

 

6,440

 

 

96,619

 

 

 

$

2,911,256

 

Proved developed non-producing

 

23,093

 

 

51,544

 

 

3,517

 

 

35,200

 

 

 

 

388,794

 

Total proved developed

 

98,225

 

 

141,823

 

 

9,957

 

 

131,819

 

 

 

 

3,300,050

 

Proved undeveloped

 

12,590

 

 

38,048

 

 

2,016

 

 

20,947

 

 

 

 

198,768

 

Total proved

 

110,815

 

 

179,871

 

 

11,973

 

 

152,766

 

$

3,043,488

 

$

3,498,818

 

 

See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 17 — Supplemental Oil and Gas Disclosures (Unaudited) for additional information on our estimated proved reserves and standardized measure.

Reconciliation of Standardized Measure to PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Standardized measure

$

2,804,857

 

$

3,564,204

 

$

3,043,488

 

Present value of future income taxes discounted at 10%

 

384,180

 

 

636,520

 

 

455,330

 

PV-10 (Non-GAAP)

$

3,189,037

 

$

4,200,724

 

$

3,498,818

 

 

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Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Oil, Natural Gas
and NGLs

 

Future
Development
Costs

 

 

(MBoe)

 

(in thousands)

 

Consolidated Entities:

 

 

 

 

Proved undeveloped reserves at December 31, 2024

 

43,840

 

$

881,182

 

Changes during the year:

 

 

 

 

Extensions and discoveries

 

123

 

 

—

 

Revisions of previous estimates

 

(1,134

)

 

(8,436

)

Acquired

 

4,880

 

 

86,722

 

Conversion to proved developed

 

(9,761

)

 

(225,496

)

Total proved undeveloped reserves changes

 

(5,892

)

 

(147,210

)

Proved undeveloped reserves at December 31, 2025

 

37,948

 

$

733,972

 

 

Our PUD reserves at December 31, 2025 decreased by 5.9 MMBoe, or 13% primarily due to:

Revisions of Previous Estimates — Downward revisions of 1.1 MMBoe are primarily related to the derecognition of approximately 2.0 MMBoe of PUD reserves associated with our South Timbalier 308 Field in the Deepwater area, resulting from a reassessment of the drilling and development plan following successful drilling at the Katmai Field. These downward revisions were partially offset by certain positive revisions at our Brutus Field driven by economics.

Acquired — Acquired PUD reserves of 4.9 MMBoe is primarily comprised of 4.5 MMBoe attributable to the acquisition of an incremental non-operated working interest in the Monument oil discovery (the “Monument Project”) in the Deepwater area. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Conversion to Proved Developed — Conversions of 9.8 MMBoe are primarily attributable to successful conversion of proved undeveloped reserves at our Gunflint Field, Sunspear Field, Cardona Field, and Ewing Bank 953 Field, which are all located in the Deepwater area.

We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves, unless the reserves are associated with an existing producing zone. Future development costs associated with our PUD reserves at December 31, 2025 totaled $734.0 million, of which $703.5 million is attributable to our Deepwater area. When considering capital expenditures associated with exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each future annual period prior to the five year expiration. Our 2026 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets.

Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2025 and 2024, all proved reserves were estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. At December 31, 2023, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI as described in further detail below.

Our policies regarding internal controls over the determination of reserves estimates require reserves quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following:

•
reserve information, as well as models used to estimate such reserves, is stored on secure database applications to which only authorized personnel are given access rights consistent with their assigned job function;
•
a comparison of historical expenses is made to the lease operating costs in the reserve database;
•
future development costs and abandonment costs associated with our proved reserves are reviewed by qualified individuals;
•
internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance analysis by well to the previous year-end reserve report is performed;
•
reserve estimates are reviewed and approved by certain members of senior management;
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our management required that the independent petroleum engineers and geologists and our reserve quantities and calculation of the net present value of the reserves, collectively, varied by no more than 10% in the aggregate when the reserves audit was conducted for the year ended December 31, 2023, in accordance with Society of Petroleum Evaluation Engineers (“SPEE”) auditing standards;
•
data is transferred to NSAI through a secure file transfer protocol site; and
•
material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and our Director of Reserves to ensure the best estimate of remaining reserves.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

NSAI estimated our proved reserves at December 31, 2025 and 2024 using deterministic methods. The estimates were prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. NSAI used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that they considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. The data used in NSAI’s estimates were obtained from us, public data sources, and the nonconfidential files of NSAI and were accepted as accurate. The NSAI report as of December 31, 2025 includes the professional qualifications for the technical persons primarily responsible for preparing the estimated proved reserves and is filed as Exhibit 99.1 to this Annual Report.

NSAI issued an unqualified audit opinion on our proved reserves as of December 31, 2023 based upon its evaluation. NSAI concluded that our estimates of reserves were, in the aggregate, reasonable and were prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

•
the quality and quantity of available data and the engineering and geological interpretation of that data;
•
estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;
•
future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC; and
•
the judgment of the persons preparing the estimates.

Qualifications of Primary Internal Engineer

With over 30 years of industry experience, the Company’s Director of Reserves is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating engagements conducted by NSAI. She holds a bachelor’s degree in civil engineering from Rafael Urdaneta University in Venezuela and a Master of Science in Petroleum Engineering from the University of Zulia in Venezuela. She worked as a reservoir and simulation engineer for Petróleos de Venezuela S.A. for 12 years before relocating to the Houston, Texas area. Prior to joining Talos as a Senior Reservoir Engineer in July 2013, she was employed as a principal reservoir engineer in Houston overseeing international projects and promoted to technical director for Latin America for two different companies for nine years. She was a Reservoir Engineering Advisor at Talos prior to becoming the Director of Reserves in April 2024. She is a member of the Society of Petroleum Engineers. The Director of Reserves reports directly to our Vice President of Strategic Planning.

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Drilling Activity

The table below notes the year in which the productive and dry wells are determined to be productive or not productive, as the case may be, as opposed to the year the well was drilled. The following table sets forth our drilling activity:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +

 

Exploratory and Appraisal Wells

 

Development Wells

 

 

 

 

 

 

Productive

 

Dry

 

Total

 

Productive

 

Dry

 

Total

 

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated Entities:

 

Year Ended December 31, 2025

 

United States

 

2.0

 

 

0.8

 

 

1.0

 

 

0.4

 

 

3.0

 

 

1.2

 

 

3.0

 

 

1.1

 

 

—

 

 

—

 

 

3.0

 

 

1.1

 

 

6.0

 

 

2.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2024

 

United States

 

—

 

 

—

 

 

2.0

 

 

0.5

 

 

2.0

 

 

0.5

 

 

4.0

 

 

1.2

 

 

—

 

 

—

 

 

4.0

 

 

1.2

 

 

6.0

 

 

1.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2023

 

United States

 

3.0

 

 

1.3

 

 

5.0

 

 

2.1

 

 

8.0

 

 

3.4

 

 

7.0

 

 

3.0

 

 

—

 

 

—

 

 

7.0

 

 

3.0

 

 

15.0

 

 

6.4

 

 

Present Activities

As of December 31, 2025, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + + + + + + + +

 

Actively Drilling or Completing

 

Wells Suspended or Waiting on Completion

 

 

Exploratory

 

Development

 

Exploratory

 

Development

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated Entities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

—

 

 

—

 

 

1.0

 

 

0.7

 

 

1.0

 

 

0.3

 

 

—

 

 

—

 

Equity Method Investees:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mexico

 

—

 

 

—

 

 

—

 

 

—

 

 

4.0

 

 

0.4

 

 

—

 

 

—

 

 

Delivery Commitments

See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on firm transportation agreements in place with transportation pipelines for future transportation of oil and gas production.

We have no firm sales commitments as of December 31, 2025.

Productive Wells

The number of our productive wells is as follows for the year ended December 31, 2025:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Gross

 

Net

 

Consolidated Entities:

 

 

 

 

Crude oil

 

216.0

 

 

161.1

 

Natural gas

 

70.0

 

 

28.8

 

Total(1)

 

286.0

 

 

189.9

 

 

(1)
Includes 7.0 gross and 5.3 net wells with dual completions.

Acreage

Gross and net developed and undeveloped acreage is as follows for the year ended December 31, 2025:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + +

 

Developed Acres

 

Undeveloped Acres

 

Total Acres

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Consolidated Entities:

 

 

 

 

 

 

 

 

 

 

 

 

United States:

 

 

 

 

 

 

 

 

 

 

 

 

Deepwater

 

428,141

 

 

248,761

 

 

581,059

 

 

310,453

 

 

1,009,200

 

 

559,214

 

Shelf

 

228,209

 

 

155,486

 

 

54,935

 

 

37,724

 

 

283,144

 

 

193,210

 

Total United States

 

656,350

 

 

404,247

 

 

635,994

 

 

348,177

 

 

1,292,344

 

 

752,424

 

Equity Method Investees:

 

 

 

 

 

 

 

 

 

 

 

 

Mexico(1)

 

—

 

 

—

 

 

3,261

 

 

572

 

 

3,261

 

 

572

 

 

(1)
Gross acreage for Mexico represents the gross acreage in Block 7, which Talos Mexico has a 35% participation interest. We hold a 50.1% equity interest in Talos Mexico. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information.
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Undeveloped acreage is considered to be leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2025 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

Consolidated Entities

 

Equity Method Investees

 

 

Gross

 

Net

 

Gross

 

Net

 

2026

 

97,920

 

 

40,678

 

 

—

 

 

—

 

2027

 

83,520

 

 

43,193

 

 

—

 

 

—

 

2028

 

29,426

 

 

15,924

 

 

—

 

 

—

 

2029

 

51,074

 

 

32,920

 

 

—

 

 

—

 

2030

 

5,760

 

 

1,728

 

 

—

 

 

—

 

2031 and beyond

 

368,294

 

 

213,734

 

 

3,261

 

 

572

 

Total

 

635,994

 

 

348,177

 

 

3,261

 

 

572

 

 

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Production Volumes:

 

 

 

 

 

 

Crude oil (MBbls)

 

24,065

 

 

24,078

 

 

18,062

 

Natural gas (MMcf)

 

46,122

 

 

41,078

 

 

26,194

 

NGLs (MBbls)

 

2,782

 

 

2,969

 

 

1,767

 

Total (MBoe)

 

34,534

 

 

33,893

 

 

24,195

 

Percent of MBoe from crude oil

 

70

 %

 

71

 %

 

75

 %

 

 

 

 

 

 

Average Sales Price (including commodity derivatives):

 

 

 

 

 

 

Crude oil (per Bbl)

$

68.18

 

$

75.07

 

$

73.59

 

Natural gas (per Mcf)

$

3.70

 

$

2.65

 

$

3.32

 

NGLs (per Bbl)

$

18.05

 

$

20.85

 

$

18.18

 

Average (per Boe)

$

53.90

 

$

58.37

 

$

59.86

 

 

 

 

 

 

 

Average Sales Price (excluding commodity derivatives):

 

 

 

 

 

 

Crude oil (per Bbl)

$

64.84

 

$

75.01

 

$

75.17

 

Natural gas (per Mcf)

$

3.67

 

$

2.57

 

$

2.60

 

NGLs (per Bbl)

$

18.05

 

$

20.85

 

$

18.18

 

Average (per Boe)

$

51.55

 

$

58.23

 

$

60.26

 

Average Lease Operating Expense (per Boe)

$

15.83

 

$

16.70

 

$

16.10

 

 

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Crude Oil, Natural Gas and NGL Production, Prices and Production Costs — Significant Fields

Deepwater Area — Katmai Field

The following table sets forth certain information regarding our production volumes, average sales prices and average production costs for the Katmai Field, which consisted of 15% or more of our 2025 total estimated proved reserves on December 31, 2025:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024(1)

 

Production Volumes:

 

 

 

 

Crude oil (MBbls)

 

3,578

 

 

2,254

 

Natural gas (MMcf)

 

7,934

 

 

4,898

 

NGLs (MBbls)

 

493

 

 

293

 

Total (MBoe)

 

5,393

 

 

3,363

 

Percent of MBoe from crude oil

 

66

 %

 

67

 %

 

 

 

 

Average Sales Price (excluding commodity derivatives):

 

 

 

 

Crude oil (per Bbl)

$

67.45

 

$

79.28

 

Natural gas (per Mcf)

$

3.98

 

$

2.59

 

NGLs (per Bbl)

$

27.70

 

$

29.89

 

Average (per Boe)

$

53.13

 

$

59.52

 

Average Lease Operating Expense (per Boe)

$

3.95

 

$

5.08

 

 

(1)
The Katmai Field was acquired as part of the QuarterNorth Acquisition. The production volumes disclosed above are for the period March 4, 2024 to December 31, 2024.

Expenditures and Costs Incurred

For information on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 17 — Supplemental Oil and Gas Disclosures (Unaudited).

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalties, overriding royalties, and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market the majority of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for expected credit losses when necessary. For the year ended December 31, 2025, 35%, 23% and 12% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company, Exxon Mobil Corporation and Chevron Corporation, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues.

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Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations.

However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploration opportunities, high margin assets concentrated in the Deepwater and significant operating control give us a strong competitive position relative to many of our competitors.

Seasonality of Business

Offshore weather conditions in the U.S. Gulf of America, particularly during hurricane and tropical storm season, may cause significant, immediate fluctuations in oil and natural gas markets by causing temporary shut-ins of offshore oil and natural gas production and forcing shutdowns or damaging coastal refineries. These events reduce supply, often leading to rapid, short-term price spikes and supply volatility. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the U.S. Gulf of America, which makes us more vulnerable to tropical storms, loop currents and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost). We may increase or decrease insurance coverage around our key assets, including potentially purchasing catastrophic bond instruments to the extent available to us.

Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $500.0 million for each occurrence and in the aggregate and includes varying deductibles. Coverage is provided for damage to our assets resulting from a named U.S. Gulf of America windstorm; however, such coverage is subject to a maximum of $250.0 million per named windstorm and in the aggregate and is also subject to a maximum of $30.0 million per occurrence retention dependent on location. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500.0 million for U.S. Gulf of America Deepwater drilling wells, $150.0 million for U.S. Gulf of America Shelf drilling wells, $75.0 million for U.S. Gulf of America producing and shut-in wells, $75.0 million for drilling and workover in inland waters and $25.0 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well becoming out of control or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws.

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Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign laws and regulations. Laws and regulations related to our business continually evolve and change depending on the political climate and regulatory regime, but generally the exploration and production industry, including our business, has been subject to increasing environmental, health and safety governmental regulations. Changes to these regulatory requirements, increased enforcement or compliance obligations, and other legal challenges to such regulations could materially impact the timing, cost, scope and feasibility of our operations, and increase capital investment and ongoing operating costs. We monitor regulatory developments closely and adjust our operational practices to maintain compliance when planning and performing our offshore Deepwater exploration and development activities.

General Overview — Our oil and natural gas operations in the Gulf of America are subject to various federal, state, and local environmental, health and safety laws and regulations, primarily enforced by two agencies:

•
BOEM oversees leasing, resource management, environmental review, and approval of exploration and development plans.
•
BSEE oversees drilling safety, production operations, equipment standards, well integrity, spill preparedness, and decommissioning.

We must also comply with regulations under the Outer Continental Shelf Lands Act, the Clean Water Act, the Oil Pollution Act, and other federal and state statutes governing offshore operations, emissions, discharges, worker safety, and spill liability. Additionally, our activities are affected by evolving federal and state environmental and operational regulations, including offshore federal lease requirements, requirements related to the exploration, production, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment and reducing greenhouse gas (“GHG”) emissions; wildlife, habitat and water protection; decommissioning and related financial assurance requirements; and the health and safety of our employees, contractors and communities where our operations are located. An overview of material regulations to which our operations are subject is set forth below.

Outer Continental Shelf (“OCS”) Regulation — Our operations on federal oil and natural gas leases in the U.S. Gulf of America are subject to extensive regulation by BSEE, BOEM and the Office of Natural Resources Revenue (“ONRR”) under the purview of the U.S. Department of the Interior (“DOI”). Federal leases are awarded by BOEM based on competitive bidding with relatively standardized lease terms and require compliance with detailed BSEE and BOEM regulations and orders pursuant to various federal laws, including the federal Outer Continental Shelf Lands Act (“OCSLA”). For offshore operations, lessees are required to obtain BOEM approval for exploration, development and production plans prior to the commencement of their operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (“EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment (“P&A”) of wells on the OCS, calculation of and valuation of production related to royalty payments, and decommissioning of facilities, structures and pipelines. U.S. federal offshore oil and gas leasing and permitting practices have been subject to numerous challenges, delays, and moratoriums which have in the past, curtailed our access to new federal leases. Any continued or future challenges or delays could prevent us from obtaining new federal leases. Recently, however, Congress and the Trump Administration have taken action to revoke or rescind certain actions that placed limitations on offshore oil and gas leasing and permitting.

The One Big Beautiful Bill Act (“OBBBA”), signed into law by President Trump in July 2025, mandated that BOEM conduct a minimum of thirty lease sales in the Gulf of America through the first half of 2040. BOEM conducted the first lease sale required under the OBBBA in December 2025. The remaining lease sales are expected to be held each March and August for the years 2026 through 2039, with the last of these mandated Gulf of America lease sales expected in March 2040. In addition to the lease sales required under the OBBBA, in November 2025, the Secretary of the Interior issued a Proposed National Outer Continental Shelf Oil and Gas Leasing Program to replace the existing 2024-2029 Five-Year Leasing Program, which began on July 1, 2024 and was set to continue through June 30, 2029. The November 2025 draft proposed program includes 34 OCS lease sales through 2031, though the substance and timing of the final program remains uncertain. Any reduction in the size or number of offshore blocks designated by BOEM for future leasing activities, as well as delays in BOEM awarding leases to high bidders either as a result of delays related to the National Environmental Policy Act or legal challenges to BOEM leasing decisions, has the potential to materially and adversely affect our business and results of operations.

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Our operations are subject to rigorous standards relating to well drilling and completion design, competency tests, operation and maintenance of blow-out preventers, real-time monitoring of Deepwater drilling activities, including high temperature, high pressure drilling activities, and enhanced reporting requirements. For example, in August 2023, BSEE, under the Biden Administration, published a final well control rule for drilling, workover, completion and decommissioning operations, revising the 2019 rule and increasing the requirements for blowout preventer systems (“BOP”) systems and other well control and operations requirements. The Trump Administration has requested comments on that final rule although it is not certain what actions the Trump Administration may take with respect to these standards, if any, once comments have been reviewed. Given the already extensive regulatory framework related to exploration and development activities in the Gulf of America, further legislative, executive and regulatory actions or other legal initiatives could result in significant costs, including increased capital expenditures and operating costs, that could adversely impact our business. Our failure to comply with legal requirements under the OCSLA, our leases or applicable regulations could ultimately result in BOEM or BSEE canceling one or more of our leases, which could adversely affect our financial condition and operations.

Furthermore, adverse weather conditions in the Gulf of America can have a significant impact on oil and natural gas operations and can result in temporarily or permanently suspended operations and significant damage to key infrastructure and extensive pollution. BOEM and BSEE have periodically issued guidance in the design of platforms and related structures in light of environmental and oceanic conditions in the Gulf. More stringent requirements could increase our operating costs and/or capital expenditures.

BOEM Financial Assurance Requirements — BOEM has generally required that lessees demonstrate financial strength and reliability under its regulatory standards, and provide acceptable financial assurances, such as surety bonds, to assure satisfaction of lease obligations, including decommissioning activities on the OCS. If BOEM determines that a lessee does not have the financial ability to meet its decommissioning and other obligations, BOEM may require the lessee to post additional financial security as assurance. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain sufficient bonds or other forms of financial assurance in all cases.

There has been substantial uncertainty with respect to BOEM’s financial assurance requirements in recent years. In April 2024, under the Biden Administration, BOEM issued a final rule entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations” which significantly increased the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule, which became effective June 29, 2024, adopted a three-year phased compliance period for fully meeting BOEM’s supplemental financial assurance demand. The final rule was challenged, and the United States District Court for the Western District of Louisiana granted a stay of litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The court’s order temporarily limits full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong. In May 2025, the DOI announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. Although the specific substance and timing of a revised rule cannot be predicted at this time, it is anticipated that the new revised rule will revert to BOEM’s former policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required. Notwithstanding the status of the final rule or a new revised rule, BOEM has stated it will continue to require lessees on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

The future cost of compliance with respect to supplemental financial assurances, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM’s final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations. Additionally, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Regulation in Shallow Waters Off the Coast of Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by various regulatory bodies. Failure to comply can result in the imposition of monetary penalties, revocation of permits, recession of the PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. Previously, the National Hydrocarbons Commission (“CNH”) was responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. However, in October 2024, the President of Mexico signed a constitutional reform dissolving the CNH. The former functions of CNH have been assigned to the National Energy Commission (“NEC”), an independent body under SENER.

In March of 2025, the new Hydrocarbons Sector Law (the “LSH”) was adopted. The LSH replaces the Hydrocarbon Law, which was in force since August 2014.

The ultimate impact of this energy reform and any future regulatory changes made pursuant to the reform is uncertain at this time. Further, the regulations governing the energy industry are subject to change, and it is possible that Mexican regulatory bodies may impose new or revised requirements that could increase operating costs and/or capital expenditures for our operations in Mexican offshore shallow waters.

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Environmental and Occupational Safety and Health Regulations

We are subject to various federal, state, local and foreign laws and regulations concerning occupational safety and health and the environment. Occupational safety and health and environmental laws and regulations relate to, among other things:

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assessing the environmental impact of seismic acquisition, drilling or construction activities;
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the generation, storage, transportation and disposal of waste materials;
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the emission of certain gases into the atmosphere;
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the monitoring, abandonment, reclamation and remediation of wells, platforms and pipelines, including those associated with former operations;
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various environmental permitting requirements, such as permits for wastewater discharges;
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the development of emergency response and spill contingency plans;
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specific operating criteria addressing worker protection; and
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protection of the waters where we operate.

Environmental liabilities and regulatory costs related to environmental protection are inherent in exploration and development activities. Based on long-term regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to safety and health compliance and environmental protection have increased over the years and are likely to continue to increase in the future. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted by legal challenges. Some environmental laws and regulations impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. The regulatory requirements related to our business frequently change and may become more stringent based on the political administration in office and resulting regulatory regime. There can be no assurance that material costs and liabilities will not be incurred in the future. More stringent regulatory requirements may result in increased costs of operations and acquisitions and decreased production and our business and financial results could be adversely affected.

We maintain insurance for spills, pollution and certain other environmental risks, although our insurance does not fully cover all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure us against pollution and similar environmental risks.

Water Discharges — Our discharges into waters of the United States are regulated by the federal Clean Water Act, as amended (“CWA”), and analogous state laws, which impose restrictions and strict controls related to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters. Failure to comply with the CWA may result in administrative, civil or criminal enforcement actions. Violations of the CWA can also result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act — The Oil Pollution Act of 1990, as amended (“OPA”), imposes certain duties and liabilities on the owner or operator of a facility, vessel or pipeline that is a source of or that poses the substantial threat of an oil discharge, or the lessee or permittee of the area in which a discharging offshore facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages.

Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages liability cap is currently $167.8 million; however, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up.

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OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration to BOEM of between $35 million to $150 million, based on a worst-case oil spill discharge volume, for companies operating on the OCS. However, BOEM may increase this amount in certain situations, but in no event greater than $150 million. If OPA is amended to increase the minimum level of financial responsibility, we could experience difficulty in providing financial assurances, in the form of surety bonds or otherwise, sufficient to comply with a significantly heightened requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

National Environmental Policy Act — The National Environmental Policy Act, as amended (“NEPA”), requires federal agencies to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment, which can lead to substantial delays in the issuance of federal permits. Following an Executive Order of President Trump, in February 2025, the White House’s Council on Environmental Quality (“CEQ”) released an interim final rule rescinding its regulations implementing NEPA. In May 2025, the Supreme Court issued its opinion in Seven County Infrastructure Coalition v. Eagle County, emphasizing the “substantial judicial deference” that courts must grant agencies when considering NEPA challenges. Federal agencies have begun preparing their own new or updated NEPA-implementing rules or guidelines and, in September 2025, the CEQ issued new guidance to federal agencies implementing NEPA to encourage them to limit their NEPA reviews, rely more heavily on sponsor-prepared documents, and streamline the NEPA process. The full impact of these developments remains unclear, but the NEPA process, which involves public input through comment as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs.

Wildlife and Habitat Protection — The Endangered Species Act, as amended (“ESA”), was established to protect endangered and threatened species. If a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds, under the Migratory Bird Treaty Act, as amended (“MBTA”), and marine mammals under the Marine Mammal Protection Act, as amended (“MMPA”).

Additionally, the U.S. Fish and Wildlife Service (“FWS”) may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist and where other species that could potentially be protected under these statutes are known to exist. The FWS or the National Marine Fisheries Service (“NMFS”) may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. For example, in April 2019, the NMFS listed the Rice’s whale as endangered under the ESA. Further, in July 2023, NMFS proposed to designate approximately 28,300 square miles of the Gulf of America as critical habitat for the Rice’s whale pursuant to a settlement agreement in a lawsuit. An amended settlement agreement further extended the deadline for NMFS to publish its final rule designating critical habitat for the Rice’s whale to no later than July 15, 2027. In addition, in July 2023, the NMFS proposed a critical habitat for the Green sea turtle, which encompasses the majority of the Gulf of America, although this critical habitat has not yet been finalized either. These actions and others may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas. The designation of new endangered species or a critical habitat for protection under the ESA, MBTA, and MMPA resulting in operating restrictions or a ban in affected areas could adversely affect our business and results of operations and increase our operating costs.

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Additionally, projects subject to agency review under the ESA can be subject to delay due to third-party challenges of the sufficiency of the ESA review. For example, in August 2024, a U.S. District Court in Maryland ruled in favor of a coalition of environmental groups that filed suit against NMFS in 2020, claiming that NMFS’s 2020 Biological Opinion, together with the associated reasonable and prudent alternative and incidental take statement, which covered all activities associated with the OCS oil and gas program in the Gulf of America, did not comply with the ESA or the Administrative Procedure Act, and vacated the 2020 Biological Opinion effective December 20, 2024. The court thereafter extended the vacatur date to May 21, 2025, pursuant to a motion filed by NMFS. In May 2025, NMFS timely published its new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. On the same day, two lawsuits were filed opposing the new Biological Opinion, one by several environmental groups (Sierra Club, the Center for Biological Diversity, Friends of the Earth and Turtle Island Restoration Network) who filed in the federal district court for the District of Maryland, and the other by the State of Louisiana, the American Petroleum Institute (“API”) and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. Both lawsuits seek declaratory and injunctive relief. On January 23, 2026, the Western Louisiana District Court judge issued a summary judgment in favor of the State of Louisiana, API and Chevron U.S.A. Inc., and found the 2025 Biological Opinion unlawful. The 2025 Biological Opinion was remanded, without vacatur, to NMFS to correct the Biological Opinion’s deficiencies. The 2025 Biological Opinion will remain active to avoid disruptive consequences to regulated parties. The outcome of the environmental groups’ challenge in the Maryland District Court remains uncertain at this time.

Hazardous Substances and Waste Management — The Resource Conservation and Recovery Act, as amended (“RCRA”), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy, the EPA and state agencies regulate these wastes as non-hazardous wastes. Regulatory agencies and environmental groups have periodically examined whether certain exploration and production wastes should be reclassified under RCRA, and future regulatory actions could result in the loss or narrowing of the current exemption. Any such changes could significantly increase our waste-handling, storage, transportation, and disposal costs. Also, ordinary industrial wastes, such as waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste. Moreover, facilities where we generate hazardous waste are subject to EPA inspection, and any noncompliance discovered or otherwise alleged by EPA can result in the imposition of substantial fines and penalties.

Comprehensive Environmental Response, Compensation and Liability Act — The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Air Emissions — The Clean Air Act, as amended (“CAA”), and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. In recent years, the EPA has developed, and, in the future may continue to develop, more stringent regulations governing emissions of toxic air pollutants and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in 2020, the EPA under the Trump Administration published a decision to retain the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone that was set by the EPA in 2015. We cannot predict what further actions, if any, the Trump Administration may take with respect to these standards, or on what timeline it may take such actions. Any revision to the NAAQS and state implementation of the same could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Climate Change — In recent years, the threat of climate change has attracted considerable public, governmental and scientific attention in the United States and in foreign countries. Numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHG as well as to restrict or eliminate such future emissions. In the United States, no comprehensive climate change legislation has been implemented at the federal level, though the EPA has adopted regulations under the existing CAA that, among other things, impose pre-construction and operating permit requirements on certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources and implement New Source Performance Standards directing the reduction of methane from certain new, modified or reconstructed facilities in the oil and natural gas sector. However, following the change in U.S. presidential administrations, proposals have been made to repeal or otherwise modify these requirements and the EPA’s GHG “Endangerment Finding,” which underpins the majority of EPA’s GHG regulations. In February, the EPA finalized a rule repealing the Endangerment Finding; however, the rule has been challenged. It is uncertain at this time what impact the repeal of the Endangerment Finding will have on current or anticipated EPA regulations, and it is not possible to determine the outcome of the challenges to the repeal.

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Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. We are not currently a defendant in any of these lawsuits but could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Certain stockholders and bondholders currently invested in fossil fuel energy companies such as ours, but concerned about the potential effects of climate change, may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. While we cannot predict how or to what extent sustainable lending and investment practices may impact our operations, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations.

Although we do not currently operate in California, the state has enacted laws requiring additional disclosure with respect to certain climate-related risks and GHG emission reduction claims. Although these laws are subject to legal challenge, to the extent compliance becomes required, any non-compliance with these laws may result in the imposition of substantial fines or penalties. Other states are considering similar laws. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.

Regulators and scientific bodies have identified GHG concentrations in the atmosphere as a factor that may contribute to changes in climatic patterns, including increased frequency and severity of extreme weather events. Our offshore operations are particularly at risk from severe climatic events, which have the potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and production operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or the products we produce. While our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Federal Regulation of Sales and Transportation of Natural Gas — Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states.

FERC anti-manipulation regulations establish violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. FERC also has authority to impose civil penalties for violations of the Energy Policy Act of 2005, the NGA and the NGPA, up to $1,584,648 per violation, per day for 2025 (this amount is adjusted annually for inflation). FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor FERC’s anti-manipulation regulations and civil penalty authority will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

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Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. Since 1978, the United States Congress has removed all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil — FERC regulates the interstate pipeline of crude oil, petroleum products and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete.

FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.

Worker Health and Safety — We are subject to the Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires that certain information about hazardous materials used or produced in our operations be maintained and provided to employees, state and local government authorities and citizens. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Human Capital

Our approach to human capital management continues to evolve as we grow our business. We strive to manage our employees in a way that supports our business strategy and promotes employee development.

Policies — Our Code of Business Conduct addresses our commitment to providing equal opportunities in employment without regard to race, color, gender identity or expression, religion, age, national origin, citizenship status, military service or reserve or veteran status, sexual orientation, or disability. We make employment and compensation decisions based on a person’s ability to perform the tasks required by their position.

We also maintain a Human Rights Policy which embodies the basic human rights tenets that we expect all employees, contractors, vendors, partners and suppliers, to follow.

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Our Code of Business Conduct and Human Rights Policy are monitored at the highest level by our Board of Directors (our “Board” or “Board of Directors”).

Please refer to https://www.talosenergy.com/investor-relations/corporate-governance/governance-documents on our website for our corporate policies. The policies referenced herein, and the information contained on or accessible through our website, are not incorporated by reference herein or otherwise made a part of this Annual Report or any of our other filings with the SEC.

Oversight and Management — The Company's executive leadership team, with oversight from various committees of the Board, sets the Company's human capital management philosophy, goals, and programs with the support of the Human Resources function, led by the Chief Human Resources Officer, who reports to the CEO.

The Compensation Committee of our Board (the “Compensation Committee”) oversees the Company’s executive compensation program, the annual incentive plan (“AIP”), the long-term incentive plan, and the overall budget for non-executive compensation. In addition, the Compensation Committee evaluates material risks related to the Company’s compensation policies and practices. The Compensation Committee also periodically assesses the Company’s compensation and benefit programs related to all employees.

The Nominating & Governance Committee of our Board (the “NGC”) reviews succession planning for the Chief Executive Officer (“CEO”) position, monitors and reviews the development and progression of potential successors and consults with the CEO on senior management succession planning. The NGC reviews with management the Company’s executive succession risks.

The Safety, Sustainability and Corporate Responsibility Committee of our Board (the “SSCR Committee”) reviews the Company’s strategies, policies and procedures related to material safety matters, and reviews the Company’s major operational risks, environmental, health and safety risks, and social and human capital risks.

Workforce Composition — As of December 31, 2025, we employed approximately 700 employees located primarily in Texas, Louisiana and Mexico. Approximately 400 (54%) of these employees are in our offshore operations and seven employees are Mexican nationals working in Mexico. In addition, we utilize third-party contract companies to provide consultants to perform various offshore and corporate services as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement.

Safety — Safety is a core value and number one priority in the operation of our business. Our focus on safety starts at the top with our Board, CEO, and Executive Vice President & Head of Operations, who is directly responsible for all safety initiatives, and the head of HSE, Regulatory and Compliance, who is dedicated exclusively to health, safety, and environmental matters. Workforce safety is also a key focus within our enterprise risk management assessment. Our Safety and Environmental Management System (“SEMS”) includes a stringent “Stop Work Authority” program which empowers all employees and contractors to stop work immediately for any safety or environmental concern without fear of retaliation or intimidation. In addition, we have implemented key behavior-based safety programs and initiatives to empower a safety-focused culture and intend to implement a human and organizational planned principles program beginning in 2026. We seek to further reinforce a safety-first mindset by linking employees’ compensation to safety performance through our AIP. Offshore employees are eligible to receive an additional quarterly safety bonus based on safety results at our offshore facilities.

Recruitment, Development and Leadership Training — We seek to recruit top talent through online recruiting platforms, referrals, university and college fairs, internships and professional recruiters. We encourage employee development through an interactive performance management process to provide feedback and growth opportunities that enable employees to advance their careers and support Talos’s strategic business goals. We also offer leadership programs and continuing education opportunities to further develop employee skills.

 

Compensation and Benefits — Our success is based on financial performance and operational results, and we believe the structure of our compensation program is an important driver of these goals. Our compensation program is designed to tie compensation to corporate and individual performance and align the interests of our employees with those of our stockholders. All full-time employees have a bonus opportunity under the AIP, which is tied to Company performance on various financial, operational, safety, environmental and strategic goals, as well as personal performance. We also utilize long-term incentive awards to motivate and retain key talent. Please refer to the section entitled “Compensation Discussion and Analysis” in our most recent Definitive Proxy Statement on Form DEF 14A, filed with the SEC on April 18, 2025 for further information on our executive compensation program and philosophy.

Another objective of our employee programs is to provide comprehensive and competitive benefits designed to attract, retain, and support a successful workforce necessary to achieve our business strategy. Such benefits include retirement savings contributions, health and wellness initiatives, mental health resources, an on-site clinic for corporate employees, and flexible work arrangements as well as matching contributions to 401(k) accounts, a company health savings account contribution, subsidized counseling, legal and financial support, a subsidy for health & fitness memberships, paid time off and leave of absence, and a work-from-home program. Through these programs, we strive to give employees the tools and resources they need to succeed both professionally and personally and to foster a safe and collaborative work environment designed to help ensure that our employees stay resilient, healthy and productive.

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Social Investment — We support a culture of stewardship through active corporate philanthropic efforts, community outreach programs, and fundraising efforts to benefit charitable organizations which contribute to the communities in which our employees work and live. In addition, we (i) provide an annual allowance to every employee that can be donated to a charitable organization of their choice, (ii) match funds raised by community committee events, (iii) budget for corporate contributions to charitable organizations and (iv) provide a paid volunteer day off for each employee each year.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to those reports, and all other information filed with or furnished to the SEC are available, free of charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s website at https://www.sec.gov.

We voluntarily publish annual sustainability reports which are available free of charge on our corporate website at https://www.talosenergy.com/sustainability/. Information included in these sustainability reports is not incorporated into this Annual Report or in any other report or document we file with the SEC.

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Item 1A. Risk Factors

We face risks in the normal course of business and through global, regional and local events that could have an adverse impact on our operations and financial performance. The following are some important risk factors that could cause our actual results to differ materially from those projected in any forward-looking statements. If any of the events or circumstances described in any of the following risk factors occurs, our business, results of operations and/or financial condition, as well as the trading price of our common stock and future prospects, could be materially and adversely affected, and our actual results may differ materially from those contemplated in any forward-looking statements we make in any public disclosures.

These risks reflect the Company’s beliefs and opinions as to factors that could materially and adversely affect the Company and its securities in the future. References to past events are provided by way of example only and are not intended to be a complete listing or representation as to whether or not such factors have occurred in the past or their likelihood of occurring in the future. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business.

Risks Related to our Business and the Oil and Natural Gas Industry

Oil and natural gas prices are volatile and prolonged price declines could materially adversely affect our business, financial condition, results of operations, cash flows, access to capital, and our ability to replace and grow future production.

Among the most significant variable factors impacting our business and financial condition are the sales prices for crude oil and natural gas that we produce.

Prices we receive for our oil and natural gas depend on numerous factors beyond our control, including, among others:

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domestic and global supply of and demand for oil and natural gas;
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market uncertainty and consumer demand levels;
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weather and natural disasters such as hurricanes and other adverse climatic conditions;
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market differentials, including quality, transportation fees, tariffs, energy content and regional pricing;
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domestic and foreign governmental actions, regulations and taxes;
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prices and availability of alternative fuels and competing energy sources;
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political instability and economic conditions in key producing regions such as the Middle East, Russia, South America, Mexico, Africa and Europe;
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armed conflicts and hostilities such as the war in Ukraine and conflicts in Israel and the Middle East;
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public health events such as epidemics or pandemics;
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actions by OPEC Plus and other major producers and governments regarding production and pricing;
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political, legal and regulatory instability in regions we currently or in the future may operate, including any prolonged government shutdowns or lapses in appropriations that could disrupt our operations and future drilling plans and opportunities;
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trade restrictions, tariffs, trade barriers, price and exchange controls;
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oil and natural gas import and export levels and prices;
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global oil and natural gas exploration, production and inventory levels;
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local supply and demand fundamentals and transportation availability;
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infrastructure constraints in processing, gathering, storage and transportation;
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speculative trading in oil and natural gas futures;
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competing supply availability and prices of oil and natural gas;
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technological advances affecting energy consumption; and
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global economic conditions.
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Given these various variables, commodity prices are inherently unpredictable. Historically, the markets for oil, natural gas and NGLs have been volatile and remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, prices have been, and may continue to be, subject to wide fluctuations. For example, during the period January 1, 2025 through December 31, 2025, the monthly NYMEX WTI crude oil price per Bbl ranged from a low of $57.97 to a high of $75.74, and the monthly NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $2.91 to a high of $4.26.

The majority of our sales are based on the spot market and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 75%, 19%, and 6%, respectively, of our estimated proved reserves as of December 31, 2025, and approximately 70%, 22%, and 8%, respectively, of our 2025 production on a Boe basis, our financial results are particularly sensitive to price movements in these commodities.

Sustained lower oil and natural gas prices adversely affect the Company in several ways:

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Lower sales value for our production reduces cash flows and net income.
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Lower cash flows may cause us to reduce our capital expenditure program, thereby potentially restricting our ability to replace and grow production and add proved reserves.
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Lower oil and natural gas prices could lead to write-downs and impairment charges in future periods, therefore reducing the carrying value of our assets and negatively impacting net income.
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Low prices could make a portion of our proved reserves uneconomic, which in turn could lead to the removal of certain of our year-end reported proved oil reserves in future periods. These reserve reductions could be significant.
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Lower oil and natural gas prices could lead to an inability to access, renew, or replace our credit facilities, impact our borrowing capacity under our credit facilities, and could also impair access to other sources of funding, potentially negatively impacting our liquidity.
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Lower prices could impair our ability to effect share repurchases because of lower cash flows.

If we are unable to replace oil and natural gas reserves, we may not be able to sustain or grow our business.

Our success depends largely upon our ability to find, develop or acquire additional economically recoverable reserves to replace or grow our proved reserves and maintain a portfolio of opportunities for future reserve additions and production over the long-term. Production from existing producing reserves naturally declines over time, requiring perpetual replacement of reserves to maintain or grow production. Our offshore E&P projects require significant upfront capital investment and extended lead times between initial discovery, project sanction and the commencement of production. As a result, changes in commodity prices, costs, market conditions or capital availability during development may negatively impact our ability to complete such projects as planned or to achieve expected returns, which could delay or reduce the addition of new reserves and production. Further, our need to generate revenues to fund operations, contribute to decommissioning activities and collateral obligations, and/or repay debt may also limit our ability to slow or shut-in production during periods of low commodity prices, which may further deplete our reserves during periods where adding reserves is uneconomical.

Exploring for, developing or acquiring reserves is highly capital intensive and uncertain. We cannot assure you that our future exploration, development or acquisition activities will result in additional proved reserves or that we will drill productive wells at acceptable costs. We may be unable to economically find, develop or acquire new reserves, particularly if our operating cash flows decline or capital becomes limited. Current market conditions could further limit financing availability, reduce acquisition opportunities, and/or further depress asset values and prices.

 

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Future exploration and drilling results are uncertain and involve substantial costs.

Drilling for oil and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs. Costs of drilling, completion and operation are often unpredictable, and operations may be curtailed, delayed or canceled due to various factors, including:

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unexpected drilling or formation conditions;
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equipment failures or accidents;
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inflation in exploration and drilling costs;
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fires, explosions, blowouts or surface cratering;
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lack of infrastructure or transportation access;
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labor shortages; and
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delays or shortages of services or equipment.

Our current operations are primarily concentrated in a single geographic region, making us vulnerable to regional risks.

Our production, revenue, reserves, and operating cash flows are derived primarily from properties in the Gulf of America. As a result, we are disproportionately exposed to regional risks such as:

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natural disasters and severe weather, such as hurricanes, winter storms, loop currents, and other adverse climatic conditions;
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changes in state or regional laws and regulations, including those imposing strict liability for pollution or requiring significant financial assurance for decommissioning;
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local price fluctuations, and gathering, pipeline, transportation and storage capacity limitations;
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production delays or regional production issues;
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limited customer base;
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infrastructure availability, including rigs, equipment, pipelines, oil field services, supplies and labor;
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access to, capacity and availability of pipelines, transportation, and/or gathering or processing that we depend on for marketing our production;
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financial assurance requirements for decommissioning obligations; and/or
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changes in laws, regulations, administration policies or court-ordered requirements that restrict or delay offshore leasing, permitting, site development or operation in federal waters where we operate.

These risks may be heightened by current geopolitical relations among Mexico, Canada and the U.S. Because most of our production is currently from properties located in the Gulf of America, adverse regional events could have a greater impact on our results of operations than on producers with more geographically diverse assets.

Global geopolitical tensions may increase volatility in oil, gas and NGL prices and could adversely affect our business.

Our oil and gas activities are affected by geopolitical and economic conditions that can cause energy market disruptions and price volatility. These include changes in energy policies, expropriation, contract cancellations or modifications, changes in laws and policies governing operations of foreign-based companies, changes in tax or royalty regimes, trade restrictions, currency fluctuations, terrorism, piracy, sanctions and armed conflicts.

Recent and ongoing geopolitical events illustrate these risks.

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Mexico and Canada: Political transitions following elections in 2024–2025 and continuing tension could lead to policy shifts or trade restrictions with the United States that affect the energy industry and broader economy.
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Russia and Ukraine: Russia’s 2022 invasion of Ukraine has led to sweeping international sanctions and countermeasures that continue to disrupt global trade and financial markets. Additional sanctions or retaliatory actions could further affect the global economy and commodity markets. A cessation of hostilities or easing of sanctions could also cause commodity prices to decline, reducing our revenues.
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Israel and the Middle East: Ongoing hostilities in Israel and the Middle East have created and may continue to create additional regional instability and supply risks.
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Venezuela: Recent U.S. intervention in Venezuela could result in associated repercussions to supply of and demand for oil and natural gas and the economy generally.

These conflicts, and any escalation or additional geopolitical crises, could result in significant volatility in energy prices, supply disruptions, and broader economic instability. We continue to monitor these and future developments, but their duration and impact are unpredictable. Any of these factors, as well as other geopolitical tensions, could adversely affect our business, financial condition, or results of operations.

Our actual recovery of reserves may differ substantially from our proved reserve estimates.

Our estimates of oil and natural gas reserves are based on judgments and assumptions about prices, costs, capital expenditures, and future production, and complex geological, geophysical, engineering and economic data. Changes in these assumptions, or differences between our interpretations and those of third-parties or regulators, can cause reserve estimates to vary significantly.

Actual production, oil and natural gas prices, costs, revenues, taxes, expenses and recoverable reserves may differ from estimates and could materially affect the quantity and value of our reserves. Our reserves may also be affected by production from adjacent properties operated by others. We regularly revise our estimates to reflect new data, production history, results of exploration and development, changes in prices, and production results. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion on 2025 changes in estimates of our proved reserves.

PV-10 is calculated using the pricing requirements established by the SEC, except it does not include estimated future income taxes, and does not necessarily represent the market value of our proved reserves. Actual future prices and costs used in computing PV-10 may be materially higher or lower. Further, actual future net revenues are affected by factors such as:

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capital expenditures and decommissioning costs;
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the rate and timing of production;
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changes in laws, regulations or taxes;
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volume, pricing and duration of our hedging contracts;
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market supply and demand for oil and natural gas;
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prices we receive for oil and natural gas; and
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our actual operating costs in producing oil and natural gas.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and natural gas industry in general.

As of December 31, 2025, approximately 22% of our proved reserves were undeveloped and 19% were non-producing. Development of these reserves requires significant capital investment and successful drilling. Actual costs or results may differ from our estimates, and some reserves may not be produced within planned timeframes or at all. Any material inaccuracy in our reserve estimates or related assumptions could adversely affect our business, financial condition, and results of operations.

Our future asset retirement obligations, including plugging and abandonment expenditures and decommissioning costs, are difficult to predict, may vary significantly from period to period and could materially adversely affect our current and future financial results.

We record a liability for the discounted present value of our asset retirement obligations, including plugging wells, removing platforms, pipelines and facilities, and restoring sites at the end of operations. As of December 31, 2025, our short-term asset retirement obligation was $112.5 million and the long-term asset retirement obligation was $1,219.6 million. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Note 9 — Asset Retirement Obligations for more information.

We have divested properties where buyers assumed abandonment obligations; however, if those parties cannot perform, we could be held jointly and severally liable for further decommissioning costs under laws such as the OCSLA. Furthermore, if non-operating partners fail to pay their share of abandonment costs, we may be required to cover those amounts. As of December 31, 2025, we have accrued $0.5 million and $21.7 million in decommissioning obligations reflected as “Other current liabilities” and “Other long-term liabilities,” respectively, on the Consolidated Balance Sheets. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Note 15 — Commitments and Contingencies for more information.

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Offshore obligations are typically more costly than onshore due to logistical challenges and stricter regulations. These estimates can change significantly due to regulatory changes, evolving technology, and the timing of abandonment, which often occurs many years in the future. As a result, we may be required to significantly increase or decrease our estimated asset retirement obligations and decommissioning expenses in future periods.

Events such as hurricanes or other natural disasters can also increase costs dramatically if platforms or facilities are damaged or not structurally intact. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged. Accordingly, our estimates of future asset retirement obligations and/or decommissioning costs could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster.

Any unexpected increase in asset retirement obligations and/or decommissioning costs could materially and adversely affect our financial position and results of operations.

We risk losing leases if we cannot drill before such leases expire.

Our leases may expire unless production is established as required by leases covering undeveloped acres. If commodity prices remain low for an extended period of time, drilling might not be economical, and some leases could expire, which could have an adverse effect on our business. As of December 31, 2025, approximately 46% of our net acreage was undeveloped. See Part I, Items 1 and 2. Business and Properties—Acreage for further discussion.

Our development plans for areas not held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, access to capital, drilling and production costs, service and equipment availability, gathering system and pipeline transportation constraints and regulatory approvals. For acreage we do not operate, we have even less control over development plans, increasing the risk of expiration.

We depend on infrastructure to market and deliver our production.

Our ability to sell our production relies in part on access to sufficient critical infrastructure, including gathering systems, pipelines, transportation, and processing facilities. If this infrastructure lacks capacity, is unavailable, or is shut down due to maintenance, weather, regulatory restrictions, legal or public opinion challenges, or other issues, we may have to shut in wells, facilities or delay development.

Inflation and interest rate changes could increase our costs.

Rising inflation and associated changes in monetary policy, including interest rates, may increase the cost of our goods, services and labor, which raises our capital expenditures and operating costs. Higher interest rates may also increase the cost of capital and slow economic growth, negatively affecting our business. Inflationary pressures continued to ease through late 2025, with annual U.S. inflation ending the year at approximately 2.7%. The U.S. Federal Reserve (the “Federal Reserve”) implemented three consecutive interest rate cuts in September, October, and December 2025, ultimately lowering the federal funds target range to 3.50%–3.75% by year‑end, down from the two‑decade highs maintained earlier in the year. Although inflation remains above the Fed’s 2% goal, policymakers signaled caution due to persistent price pressures and a softening labor market, leaving uncertainty around the pace and timing of any additional rate cuts in 2026. Continued inflation and volatile energy prices may further increase the cost of goods, services, and labor, driving up operating expenses and capital spending. We cannot predict future inflation or monetary policy trends.

We may not be able to obtain sufficient surety bonds on reasonably acceptable terms to conduct our business.

The offshore surety bond market has undergone a structural shift driven largely by adverse developments in restructurings and bankruptcies of companies operating in the OCS, leading to materially reduced availability of surety bonds as a number of surety companies have exited the offshore surety market. In addition, remaining surety companies generally have a lower risk tolerance which has increased pressure to provide collateral on existing and new surety bonds. As a result, new surety bonds may not be available to us on commercially reasonable terms, including requiring collateral, which may lead to significantly increased costs on our operations. Further, if surety market conditions continue to tighten, there may not be sufficient surety bond capacity available for companies in the OCS which could consequently have a material adverse effect on our ability to conduct and grow our operations in the region.

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In November 2025, we entered into various collateral and security arrangements with our surety bond providers to limit the amount of collateral we are required to provide on existing surety bonds through 2031. In return for our agreement to post annual collateral commitments and make minimum plugging and abandonment expenditures, our surety providers agreed not to require additional collateral under their existing surety agreements above the agreed upon amounts, draw on letters of credit posted for the sureties’ benefit, or cancel any existing surety bonds. The arrangements generally contain certain events of default which, if triggered and not cured by us within the cure period, would terminate the standstill period and provide the sureties their full rights under their respective surety and indemnity agreements, including the right to call collateral. Events of default include, but are not limited to, the failure to maintain liquidity of $200.0 million or above a specified credit rating. Please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for further information about these arrangements, our collateral funding requirements and plugging and abandonment commitments. New surety bonds are not subject to these collateral limits, and we may therefore have to post increased collateral on new bonds.

BOEM also requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances, such as surety bonds, to meet lease obligations, including decommissioning activities on the OCS. In 2024, BOEM adopted a new financial assurance rule that significantly increased supplemental bonding requirements for certain lessees and grant holders conducting operations in the OCS. The final rule was challenged in court by multiple oil and gas industry groups and the states of Mississippi, Louisiana and Texas. The U.S. District Court for the Western District of Louisiana granted a stay of the litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The court’s order temporarily limits full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.

In May 2025, the DOI announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. Although the specific substance and timing of a revised rule cannot be predicted at this time, it is anticipated that the new revised rule will revert to BOEM’s former policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required. Notwithstanding the status of the final rule or a new revised rule, BOEM has stated it will continue to require lessees on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of their decommissioning liabilities. Despite expected changes to the BOEM financial assurance rule, we remain subject to existing bonding requirements, and future rules are uncertain. In the future, BOEM could implement new or revised rules that require additional financial assurances in material amounts. BOEM may reject proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities or the availability of surety bonds in the market on acceptable commercial terms. If we cannot provide required assurances on acceptable terms, BOEM could impose penalties, suspend operations, or cancel leases. Surety companies may also demand additional collateral on future surety bonds, which could reduce our liquidity and limit future capital spending. Market conditions and regulatory changes could continue to further affect the availability and costs of future surety bonds, materially impacting our ability to operate on the OCS. After 2031, under our existing and future indemnity agreements, surety companies have the right to demand additional collateral to support currently existing bonds. We cannot provide assurance that we will be able to satisfy future collateral demands. Collateral in the form of cash or letters of credit would negatively impact our liquidity position, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook.

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Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.

As an exploration and production company, we rely heavily on information and operational technology systems to support our exploration, production, and administrative functions across our offshore and corporate operations. The energy sector’s growing reliance on information and operational technology to manage critical business functions has significantly increased the exposure to cybersecurity threats. As such, our systems face increasing technological and cybersecurity threats which could result in unauthorized access to sensitive information or render our systems unusable. For example, a cyber-attack on a production control system could result in significant environmental and safety risks, such as a well incident, shut-in or spill that could cause business interruption, reputational damage, regulatory fines or penalties, costs of compliance or remediation or insurance limitations. Other examples of cybersecurity threats we may face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry. Our customers, suppliers, subcontractors and joint venture partners also face similar cybersecurity threats, which may impact us. We rely on third-party vendors and service providers, including, but not limited to, software and hardware suppliers, cloud-based service providers, and industrial equipment manufacturers, which may present additional cybersecurity risks to us beyond our direct control if their systems or supply chains are compromised. Any successful cyber breach, whether of our systems or those of a third-party provider, could compromise our systems, disrupt our operations, or result in the unauthorized disclosure of sensitive information and/or infrastructure or environmental damage. Such incidents could result in regulatory investigations, litigation, fines and penalties, reputational damage, and significant costs for compliance, remediation and system restoration.

Although we maintain risk-based security programs integrated with enterprise risk management, which include, but are not limited to, cybersecurity oversight, detection and response processes, third-party risk management, and cyber incident insurance, these measures may not prevent or fully cover losses. Attack techniques continue to evolve, and some breaches may go undetected for extended periods. Breaches of our information and operational technology systems, or any material outage or data compromise could materially affect our operations, and financial condition, damage our reputation, lead to financial losses from remedial actions, loss of business, and potential liability, and impact our ability to meet regulatory obligations.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As of December 31, 2025, approximately 19% of our production is from properties we do not operate. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such properties to fund their contractual share of the capital and operating expenditures. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on such properties during periods of lower crude oil or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these properties could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

Hedging transactions may limit our potential gains and expose us to other risks.

We use hedging transactions, such as futures contracts on the NYMEX, to manage price volatility for oil, natural gas, and NGLs. While these arrangements help reduce downside risk, they can also limit potential gains if prices rise above hedge levels. In certain circumstances, such transactions may expose us to the risk of financial loss, including instances in which:

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our production is less than expected or is shut-in for extended periods;
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there is a widening of price differentials between delivery points;
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the counterparties default;
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there are unexpected market events which materially impact oil or natural gas prices; or
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we are unable to market our production as planned.

Future collateral requirements depend on market conditions. These factors could increase costs or liquidity needs and negatively affect our financial results.

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Compliance with environmental laws, including legal requirements related to marine life and endangered and threatened species, could increase our costs and limit operations.

Our offshore operations are subject to stringent federal, state and/or local environmental laws and regulations governing emissions, waste disposal and the protection of marine life and endangered species. These regulations require permits, restrict or prohibit certain activities within protected areas or that may affect certain wildlife, including marine species and endangered and threatened species and impose substantial liabilities for pollution. Additionally, the threat of climate change has, in recent years, been a heightened area of litigation, regulations and disclosure requirements in the United States. Although federal efforts seeking to mandate climate-related disclosures have not been successful, many other environmental requirements remain in place, and future changes to environmental restrictions and regulations remain uncertain. Further, states and other jurisdictions may impose stricter standards in the future. Any legal developments that increase compliance costs or restrict drilling could have a material adverse effect on our business, results of operations and financial condition. For additional information about government regulation related to environmental and worker safety matters, please see Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations.

Regulatory changes could restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to leases, which could have a material adverse effect on our business, financial condition or results of operations.

Our industry and oil and gas operations are subject to numerous U.S. federal, state and local laws. These regulations govern all aspects of our operations, including permits, environmental protections, emissions, drilling plans, transportation and service infrastructure, bonding for decommissioning, reporting and taxation related to our operations. Stricter environmental, health and safety standards applicable to our operations and those of the oil and gas industry more generally have been implemented during prior U.S. presidential administrations. For example, over the past decade, BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Effective October 2023, BSEE published a final rule requiring, among other things, that a blowout preventer system is able to close and seal the wellbore at all times to the well’s maximum kick tolerance design limits and more stringent requirements for failure reporting. The current presidential administration has stated its intent to reduce various regulatory burdens for fossil fuel projects although future regulations may vary under various political leadership. In Mexico, recent energy reforms have strengthened state control and introduced new permitting and unitization procedures under SENER and the newly formed National Energy Commission (CNE).

Failure to comply with any regulations applicable to our operations can result in significant administrative, civil or criminal penalties, injunctions and other restrictions on our operations or reputational harm. In addition, because we hold federal leases, the U.S. federal government requires us to comply with numerous additional regulations applicable to government contractors. Future, more strict regulations, executive orders, or agency actions could restrict offshore leasing, delay projects, increase compliance costs, or limit access to drilling locations. Litigation challenging leasing programs and future federal policies under different political leadership add uncertainty. These changes could result in higher bonding requirements, penalties, or suspension of operations, which may materially affect our business and financial results. Also, if material spill incidents occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws, legal proceedings or regulations on our drilling and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

Production shut-ins could increase costs and reduce future production.

If we are forced to shut-in wells, restarting production may require significant expense and could make some wells uneconomic at low prices, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, production levels may be lower than before, and we may need to permanently discontinue development plans or production. Any prolonged shut-in or curtailment could negatively affect our reserves, financial condition and results of operations.

Severe weather or public health events could disrupt production and reduce revenues.

We may experience significant shut-ins and losses of production due to events outside of our control, such as adverse weather conditions. As an offshore exploration and development company with significant assets in the U.S. Gulf of America, our operations are particularly vulnerable to hurricanes, tropical and winter storms, loop currents, and other adverse weather conditions in the region. Further, our operations could be disrupted by epidemics, outbreaks or other public health events such as in 2020 by Covid-19. A regional or global public health crisis could also disrupt operations by causing workforce shortages, supply chain interruptions, or government-imposed restrictions. Any prolonged disruption could materially affect our production, revenue, and financial condition.

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We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. For example, a hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of America windstorm, oil pollution, construction risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles or retentions, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and we may experience production interruptions for which we do not have production interruption insurance. There is no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage.

We may also be liable for damages from an event relating to a project in which we own a non-operating working interest and over which we have limited control. Any event resulting in a significant interruption to our business, whether covered by insurance or not, could severely impact our financial position.

We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage or self-insure. Further, we may not be able to secure additional insurance or financial assurance surety bonds that might be required by future governmental regulations. This may cause us to restrict our operations in the areas in which we operate, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could materially and adversely affect our financial condition, cash flows, business properties, liquidity and results of operations.

Our actual production could differ materially from our forecasts.

We periodically provide production forecasts and guidance based on assumptions about existing wells and anticipated operating conditions. Such forecasts do not reflect all possible impacts which are outside our control, such as unanticipated facility or equipment malfunctions, adverse weather effects outside budgeted expectations, adverse resolutions to disputes relating to operatorships, unanticipated regulatory and legal impacts, or significant declines in commodity prices or material increases in costs. If risks occur that significantly impact our operations and costs, actual production could be materially lower than anticipated, which may make certain production uneconomical and negatively effect our financial results.

Our strategy emphasizes Deepwater exploration and development, which involves significantly higher operational and financial risks than operations in shallower waters. Deepwater activities in the Gulf of America are complex, capital‑intensive, and subject to a wide range of uncertainties.

We generally focus on Deepwater exploration and development, primarily in the Deepwater Gulf of America. Exploration for oil or natural gas in Deepwater regions, including the Gulf of America, generally involves greater operational and financial risks than exploration in the shallower waters and require advanced technology, specialized rigs, and extensive subsea infrastructure. Deepwater conditions increase the likelihood of technical challenges, including geological complexity, high temperatures and pressures, and other drilling risks. As a result, wells may experience operational obstacles, be non‑commercial, may take longer to drill, or may not produce sufficient revenue to recover drilling and development costs.

Our operations are also subject to unexpected drilling conditions, equipment failures or accidents, extreme weather, labor and supply‑chain shortages, and other operational delays. Limited infrastructure in Deepwater areas may extend the time between discovery and first production, and in some cases, may render discoveries uneconomic to develop. We may also pursue future exploration and development opportunities internationally, where similar Deepwater risks would apply.

Deepwater operations also carry significant environmental risks. Failure to manage inherent operational risks related to exploration, development, production and decommissioning can result in unexpected incidents, such as oil spills, explosions, mechanical failures, or loss of well control causing personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruptions of operations. For example, an oil spill or substantial threat of discharge could result in strict liability for cleanup costs, natural resource damage, economic losses, and other penalties. Such events could materially and adversely affect our financial condition.

In addition, fluctuations in oil and natural gas prices affect both the demand for and cost of drilling rigs, equipment, and related services, which may further increase the overall cost and risk of Deepwater projects.

If any of these risks materialize, we could incur substantial losses, including property damage, environmental remediation costs, fatalities or serious injuries, regulatory investigations or penalties, prolonged operational downtime, and significant repair expenses. Any of these events could have a material adverse effect on our business, financial condition, and results of operations.

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Intense industry competition could limit our growth and increase costs.

We operate in a highly competitive industry where many of our competitors are larger and have substantially greater financial resources. These companies may outbid us for leases and acquisitions, and have more capital to make acquisitions, enter into joint ventures, attract and retain skilled personnel, obtain equipment, and invest in advanced technologies. Such competition can significantly reduce our opportunities for growth, increase costs and limit our access to resources. In addition, larger, more diverse competitors with greater financial resources may be better able to respond and adapt to adverse economic and industry conditions, including price fluctuations, reduced demand, and current and future regulatory requirements and taxes. If we cannot compete effectively and economically, our revenues and growth prospects could be materially affected.

The loss of a significant customer could materially reduce our revenue and materially adversely affect our business.

We rely on a limited number of customers for a substantial portion of our revenue. The loss of any large customer, such as Shell Trading (US) Company, Exxon Mobil Corporation and Chevron Corporation, which represent 35%, 23% and 12% of our oil, natural gas and NGL revenues for the year ended December 31, 2025, respectively, could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for additional information.

We rely on skilled and experienced personnel, and shortages in such personnel, higher labor costs or the loss of key management could adversely affect our ability to operate.

Our offshore exploration, production and decommissioning activities rely on highly skilled, experienced, and technical personnel. The loss of key individuals or our inability to attract and retain skilled workers could negatively affect our productivity, profitability, and growth. Competition for specialized talent is intense in our industry, and labor costs may rise due to market conditions or unionization. These factors could impair our ability to operate effectively and economically. In addition, unanticipated changes in management turnover may impact our ability to effectively implement our strategy and manage our business.

We have various contractual commitments. Our failure to satisfy these commitments could adversely affect our results of operations and financial position.

Contracts customary in our industry may expose us to significant economic loss. We have entered into, and may in the future enter into, transportation and other commercial arrangements that include minimum volume commitments, which could expose us to significant contractual penalties and fees if our production declines and we cannot meet these commitments. As of December 31, 2025, our future minimum transportation fees totaled approximately $43.9 million through 2030. Failure to satisfy these commitments could reduce our cash flow from operations, which may require us to delay investments, reduce capital expenditures, or seek alternative financing. Similarly, we may enter into drilling rig and other certain vessel contracts that require significant financial commitments, have high operating and standby rates, and include significant penalties for termination. These outcomes could materially and adversely affect our results of operations and financial condition. Further information about these commitments can be found under Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies.

We have operations in multiple jurisdictions and our tax obligations and related filings are complex. In addition, changes in tax laws or their interpretation could increase our tax obligations and reduce after-tax profitability.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in various U.S. state and local and non-U.S. jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Our after-tax profitability depends on numerous factors, including the availability of tax deductions, credits, exemptions, refunds and other benefits to reduce our tax liabilities, the allocation of earnings among jurisdictions, and the treatment of intercompany transactions. We also may expand our operations into new jurisdictions which could subject us to additional significant tax liabilities.

Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions and interpretations, in each case, possibly with retroactive effect. From time to time, U.S. federal and state legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any changes could take effect. In addition, states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. The passage of any such legislation or other future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdiction in which we operate or have subsidiaries now or in the future could increase our future tax liabilities and adversely impact our after-tax profitability.

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Our future tax liabilities may be greater than expected if our ability to use our net operating loss (“NOL”) and interest expense carryforwards are limited, which may adversely affect our results of operations and cash flows.

As of December 31, 2025, we had approximately $139.3 million of U.S. federal tax-affected NOL carryforwards and $16.4 million of state tax-affected NOL carryforwards. Some of our U.S. federal NOL carryforwards expire in 2036 while others have no expiration date. The state NOL carryforwards have no expiration date. As of December 31, 2025, we also had $40.2 million of tax-affected U.S. federal and state interest expense carryforwards. Utilization of these NOL and interest expense carryforwards depends on various factors, including future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”) generally imposes an annual limitation on the amount of NOL and interest expense carryforwards that a corporation can use to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). Under Section 382 of the Code, an ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of a corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. Most of our U.S. federal NOL carryforwards and certain of our interest expense carryforwards are currently subject to limitation under Section 382 of the Code. In the event we were to undergo an ownership change in the future, utilization of our NOL and interest expense carryforwards would be subject to further limitation under Section 382 of the Code. Similar limitations apply under state income tax laws. Any unused annual limitation generally may be carried over to later taxable years. If we are unable to fully utilize these carryforwards, our future tax liabilities could be greater than expected, which may adversely affect our results of operations and cash flows.

Our Mexican operations are subject to evolving regulatory and environmental requirements that could increase costs and create compliance risks.

Through our ownership in Talos Mexico, we hold a non-operated interest in oil and gas properties in shallow waters off the coast of Tabasco, Mexico that are subject to regulation by SENER, ASEA and other Mexican authorities. The legal framework for the Mexican energy sector has undergone significant reform and continues to evolve. Future changes in laws, regulations, or administrative practices could impose new or more stringent requirements, increasing our operating costs or capital expenditures in the region.

See Part I, Items 1 and 2. Business and Properties — Government Regulation for additional disclosure relating to the legal requirements imposed by Mexican regulatory bodies to which we may be subject in the pursuit of our operations conducted through our equity method investment.

Additionally, under our Block 7 PSC, we are jointly and severally liable for all obligations under the PSC, including exploration, development, appraisal, extraction, abandonment and environmental compliance. Failure to meet these obligations could result in penalties or contractual rescission of the PSC. See Part I, Items 1 and 2. Business and Properties — Mexico for more information regarding our ownership interest in Talos Mexico.

We may also seek to expand our operations in offshore Mexico in the future, and any such expansion could subject us to additional operational, regulatory, tax, and political risks associated with conducting business in that region.

Seismic data interpretation does not guarantee the presence of commercially viable hydrocarbons.

We rely on three-dimensional seismic studies to evaluate drilling opportunities on our properties and potential acquisitions. These studies are interpretive tools and cannot ensure that hydrocarbons are present or, if present, that they can produce in economic quantities. Seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. As a result, drilling based on seismic data may lead to unsuccessful drilling and operational results, which could adversely affect our operational results and financial condition.

Violation of anti-corruption laws, including the U.S. Foreign Corrupt Practices Act, could result in severe penalties and loss of key contracts.

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and similar laws that prohibit improper payments or offers of payments to foreign officials and political parties to obtain or retain business. Operating in certain jurisdictions may expose us to demands from government officials or other parties in violation of the FCPA. Despite our compliance policies and training, we face the risk that employees or third-party representatives might engage in prohibited conduct for which we might be held responsible.

Under the Block 7 PSC with the CNH, to which a subsidiary of Talos Mexico is a party, violations of the FCPA, by any signatory could result in significant criminal or civil sanctions and allow CNH to rescind the PSC. Such event could materially and adversely affect our business, operating results and financial condition.

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Our business faces risks related to climate change concerns that could increase our operating costs, restrict where we can operate, and reduce demand for the crude oil and natural gas that we produce.

Climate change continues to attract public, political and scientific attention both domestically and abroad. For example, the Inflation Reduction Act of 2022 (the “IRA 2022”) contained hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels, electric vehicles and supporting infrastructure, and carbon capture and sequestration, among other provisions. However, certain of these incentives and initiatives have been paused, repealed or otherwise modified due to the passage of the OBBBA. The IRA 2022 also imposed the first ever federal fee on the GHG emissions through a methane emissions charge, although the OBBBA postponed the implementation of the methane emissions charge until 2034.

These legislative and regulatory changes could ultimately decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.

Additional federal, state, and local initiatives, including potential carbon taxes, cap‑and‑trade programs, mandatory GHG reporting, and rules that directly limit emissions, could further increase compliance costs or restrict development activities. International actions to regulate or limit GHG emissions may have similar effects. Climate‑related political, financial, and litigation pressures on fossil fuel producers may also continue to grow. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations — Climate Change for additional disclosure relating to risks arising out of the threat of climate change.

Future legislation or regulatory programs designed to reduce or eliminate GHG emissions may require us to install new emissions‑control equipment, purchase emissions credits, or comply with additional reporting or operational requirements. These measures could increase the cost of consuming hydrocarbons and reduce demand for the oil and natural gas we produce. They may also cause us to delay, limit, or cancel projects or impair our ability to operate economically.

Any of these factors such as regulatory changes, increased compliance costs, reduced product demand, or climate‑related operational constraints, could negatively affect our business, financial condition, and results of operations.

Evolving expectations, regulations and related scrutiny regarding environmental, social and governance matters could impact our business and stock price.

In past years, there has been increased attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fossil fuels. Although recent U.S. political trends have shifted away from certain environmental, social and governance initiatives, these matters remain highly relevant to our future strategy and business. Future shifts in investor priorities, regulatory requirements, or societal expectations could increase costs, limit demand for our products, reduce profits, or affect access to capital, which could negatively impact our stock price.

While we endeavor to publish transparent sustainability reports, the voluntary disclosures in these reports rely on assumptions and estimates or hypothetical scenarios that may not reflect actual outcomes, and they are increasingly subject to scrutiny for accuracy and potential “greenwashing.” Regulators, investors, and other stakeholders may challenge our statements or goals, which could lead to investigations, litigation, reputational harm, and additional compliance costs. Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private sector actors have also filed lawsuits under various securities and consumer protection laws alleging that certain statements related to environmental, social or governance goals or commitments were misleading, false, or otherwise deceptive. Certain employment or business practices and inclusion initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors. The complex regulatory and legal frameworks applicable to such initiatives continue to evolve.

In addition, organizations that provide information, ratings or proxy advisory services to investors on corporate governance and related matters have developed processes for evaluating companies on their approach to environmental, social and governance initiatives. Such ratings or recommendations and reports are used by some investors to inform their investment and voting decisions. Unfavorable ratings or recommendations may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. We may also face criticism or legal challenges from parties proposing or opposed to environmental, social and governance initiatives, including claims that our environmental or social commitments are inconsistent with evolving laws. These risks could disrupt operations, increase expenses, and negatively affect our stock price and ability to attract customers, employees, and investors.

Changes in U.S. trade policy, including tariffs or other restrictions, could increase costs and adversely affect our business.

There has been continued uncertainty about U.S. trade policies, treaties, tariffs, taxes, and other limitations that could impact our costs and supply chain. Such tariffs and any additional tariffs, trade barriers, or retaliatory measures could further increase the cost of materials and services we use, disrupt our supply chain, and negatively affect our business, prospects, financial condition and operating results.

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We may not realize expected benefits from future acquisitions, and integration challenges could harm our business.

Our growth strategy includes pursuing acquisitions. However, we may not achieve anticipated benefits such as increased earnings, cost savings, operational efficiencies, or reserve additions. Challenges may include higher-than-expected costs, inaccurate reserve estimates, unknown liabilities, challenges operating in new geographic regions and under new regulatory frameworks, and difficulties integrating operations, systems, corporate functions, and personnel. In addition, integrating acquired assets can increase indebtedness, divert management’s focus, and involve difficulties associated with operating a larger or geographically diverse organization. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. If we cannot successfully integrate acquired businesses or realize expected benefits, our business, financial condition, and results of operations could be adversely affected.

Acquisitions and current assets expose us to potentially significant liabilities, including abandonment obligations.

We evaluate factors such as reserve estimates, the timing of recovering reserves, exploration potential, future prices, operating costs and potential environmental and regulatory liabilities, including P&A liabilities and decommissioning obligations when leasing or acquiring oil and gas properties. These assessments are inherently uncertain and may not identify all issues. Reviews may miss defects or liabilities, and we may acquire properties on an “as-is” basis with limited contractual protections.

We may face claims related to environmental, title, regulatory, tax, contract, litigation or other matters that were unknown at the time of acquisition. While we may be able to obtain indemnities for certain pre-closing liabilities, these protections are typically limited in scope and duration and often are insufficient to cover the full liability. If sellers or other parties fail to meet their obligations, we could be responsible for significant costs, which could materially and adversely affect our operations, financial condition, and results.

Litigation outcomes could materially affect our financial condition.

We may be involved in legal proceedings, and an unfavorable resolution could have a material impact on our financial position and results of operations. If potential liabilities are not fully covered by insurance, or if coverage is inadequate, we could incur significant losses. See Part I, Item 3. Legal Proceedings for more information.

Lower oil and natural gas prices and other factors have resulted in, and may in the future result in additional, ceiling test impairments and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Impairment of oil and natural gas properties” on the consolidated statements of operations and an increase to “Accumulated depreciation, depletion and amortization” on our consolidated balance sheets. An impairment of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to impair the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, impairments may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional impairments of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. For the year ended December 31, 2025, the Company recorded an impairment of $454.5 million. Any required impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

A prolonged government shutdown or lapse in federal appropriations could disrupt our offshore operations and delay required regulatory approvals.

From time to time, the U.S. federal government has experienced periods of prolonged shutdowns. A prolonged government shutdown, lapse in federal appropriations or other resulting restrictions on federal agency operations could result in significant delays or interruptions in future federal lease sales, permitting, inspections, approvals, decommissioning plans, and other agency actions (including actions by BOEM, BSEE, US. Coast Guard) upon which our offshore exploration, development and production activities in the U.S. Gulf of America depend. Such delays could increase project timelines, cause suspension or postponement of planned drilling plans, completion, tie-ins or platform work, and could decrease production, postpone capital projects, increase other costs or delay revenues, which could have a material adverse effect on our business, results of operations and cash flows.

In addition, a government shutdown could affect supply-chain timing and create macroeconomic uncertainty that affects commodity markets and project financing which could materially adversely affect our financial condition, liquidity and results of operations.

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We previously identified material weaknesses in our internal control over financial reporting that could have, had they not been remediated, resulted in material misstatements in our financial statements and caused us to fail to meet our reporting and financial obligations.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

In September 2024, the Company identified two material weaknesses. Management, under the oversight of our Audit Committee, took steps to fully remediate the material weaknesses as described more fully in Part II, Item 9A. Controls and Procedures of our Annual Report on Form 10-K for the year ended December 31, 2024. The Audit Committee did not identify any related material errors in the Company’s historical financial statements.

We can give no assurance that additional material weaknesses will not arise in the future. The development of any new material weaknesses in our internal control over financial reporting could result in material misstatements in our consolidated financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition, results of operations or cash flows, restrict our ability to access the capital markets, require significant resources to correct the material weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in both investor confidence and the market price of our stock.

Risks Related to our Capital Structure and Ownership of our Common Stock

Our debt level and related covenants in our current or future credit agreement and indentures could restrict our operations, and failure to comply with the covenants could result in accelerated payment obligations.

The agreements governing our debt may impose significant restrictions limiting our ability to take certain actions, including:

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incurring additional debt;
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paying dividends, redeeming stock or redeeming subordinated debt;
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making certain investments;
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creating liens;
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selling assets;
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guaranteeing other indebtedness;
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entering into agreements that restrict dividends from our subsidiaries;
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merging, consolidating or transferring all or substantially all of our assets;
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hedging production; and
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entering into certain transactions with affiliates.

These restrictions reduce our financial flexibility and may limit our ability to respond to changing business conditions or pursue growth opportunities. Our debt obligations require substantial cash flow for interest and principal payments, which reduces funds available for operations, capital expenditures, and other business needs. In addition, high levels of outstanding debt may:

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limit our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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detract from our ability to successfully withstand a downturn in our business or the economy generally; and
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place us at a competitive disadvantage against other less leveraged competitors.

In addition, borrowings under our Bank Credit Facility bear interest at variable rates, making us sensitive to rate increases. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information on the Bank Credit Facility and Senior Notes.

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If we fail to comply with covenants and other restrictions in our debt agreements, including financial ratio requirements, it could result in an event of default and the acceleration of repayment. Our ability to comply with covenants and other restrictions may be affected by events beyond our control, including economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas.

We depend on our A&R Credit Agreement for a portion of our future capital needs. Our borrowing base under the new credit facility is subject to semi-annual redetermination based on proved reserves. Such borrowing base determines the amount which is available under the facility. If our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such deficiency or take other corrective actions. Specifically, we are allowed to cure a borrowing base deficiency by: (i) repaying amounts outstanding sufficient to cure the borrowing base deficiency within 30 days; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient cash flows from operating activities to meet our debt obligations. If we do not have sufficient cash to repay our indebtedness, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. However, our A&R Credit Agreement and indentures may prohibit us from taking such actions, and we may not be able to refinance or restructure our indebtedness on acceptable terms, and any refinancing could involve higher interest rates and more restrictive covenants. In addition, financial market conditions, our market value, and operating performance may limit our ability to conduct equity offerings, refinance our debt or sell assets.

The Carlos Slim family’s significant ownership and voting power may create conflicts of interest and influence shareholder votes and major strategic decisions.

As of December 31, 2025, Control Empresarial de Capitales, S.A. de C.V. (“Control Empresarial”), an entity controlled by the family of Carlos Slim Helú (collectively, the “Slim Family”) beneficially owned and possessed voting power of approximately 25.8% of our outstanding common stock. This ownership gives the Slim Family significant influence over matters requiring stockholder approval, including changes in capital structure, mergers or acquisitions, and corporate governance. Their interests may differ from those of other stockholders, and they may make decisions that are adverse to other stockholders’ interests.

This concentration of voting power could influence a sale of our company and may discourage third parties from seeking to acquire our common stock which could negatively impact the market price of our common stock. Although we and affiliates of the Slim Family have extended the standstill arrangement through December 16, 2026, the agreement does not restrict voting rights or other actions. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Related Party Transactions for additional information on the cooperation agreement with Control Empresarial.

A financial crisis or disruption in credit markets could limit our access to funding and adversely impact our ability to do business.

We fund our operations and capital expenditures primarily through cash flow from operations and borrowings under our bank credit facility. We may also seek funding from capital markets or asset sales for additional liquidity. A financial crisis or market disruption could reduce our ability to access these sources of funding. For example, our borrowing capacity under our bank credit facility could be limited by a borrowing base reduction, availability cap, financial covenant breach, or lender non-performance.

Broader market instability could also restrict access to debt and equity markets, increase counterparty credit risk, and require us to post additional collateral under certain agreements. If we cannot obtain adequate financing, we may need to delay investments, sell assets, or seek alternative funding on unfavorable terms, any of which could materially affect our financial condition and results of operations.

From time to time, we may retire or repurchase outstanding debt through cash payments, exchanges for equity or debt, or other transactions, depending on market conditions, liquidity needs, and contractual restrictions. These transactions could be material and may result in taxable cancellation of indebtedness income or limit our ability to deduct future interest expenses, which could create current or future tax liabilities and adversely impact our ability to deduct interest expenses in the future. This could result in a current or future tax liability and could adversely affect our financial condition and cash flows.

We require substantial capital to fund our operations and replace our production and may not be able to obtain financing on acceptable terms.

Our business requires substantial capital for acquiring, developing, and producing oil and natural gas reserves. We fund these expenditures primarily through operating cash flow, cash on hand, and borrowings under our A&R Credit Agreement. The amount and timing of future spending depend on factors beyond our control, including commodity prices, drilling results, service, infrastructure and equipment availability, and regulatory, technological and competitive developments.

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If oil and natural gas prices decline or other factors reduce our cash flow or borrowing capacity, we may be unable to fund planned projects. In that case, we may need to raise additional debt or equity or sell assets, and we cannot assure you that such financing will be available on favorable terms, or at all. Limited access to capital could reduce our ability to replace reserves and grow production, which may adversely affect our business and financial condition.

As a holding company, we depend on distributions from Talos Production Inc. and our subsidiaries to meet our obligations.

We are a holding company that has no material assets other than our ownership of Talos Production Inc. We have no independent source of revenue. We rely on cash distributions from Talos Production Inc. to pay taxes, cover corporate expenses, and, if declared, pay dividends on our common stock. Although we do not expect to pay dividends on our common stock in the near term, if our Board of Directors decides to do so in the future, our ability to pay dividends will depend on Talos Production Inc.’s ability to make distributions to us, which is subject to restrictions under its debt agreements and applicable law. If Talos Production Inc. is unable to make distributions, our liquidity and financial condition could be materially adversely affected. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information.

Our charter allows certain directors and stockholders to pursue business opportunities that may not be offered to us.

Subject to the limitations of applicable law, our charter permits directors and officers affiliated with principal stockholders to engage in activities that may compete with us and to pursue business opportunities without offering them to us. These provisions also allow transactions between us and entities in which our directors or officers have an interest. Specifically, our Second Amended and Restated Certificate of Incorporation:

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permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
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permits our officers or directors who are also officers, directors, employees, managing directors, or other affiliate of a Principal Stockholder (as defined in the Second Amended and Restated Certificate of Incorporation) to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
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provides that if any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Principal Stockholders becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.

Currently, none of our directors or officers are affiliated with a Principal Stockholder. However, these provisions create the possibility that business opportunities that might otherwise be available to us could be directed to other parties, which may limit our ability to pursue certain transactions and could adversely affect our growth prospects.

Our charter includes exclusive forum provisions that may limit stockholder’s ability to choose a judicial forum for disputes.

Our Second Amended and Restated Certificate of Incorporation provides that, unless we consent otherwise, certain claims, including derivative actions, fiduciary duty claims, and matters governed by Delaware law, must be brought in the Delaware Court of Chancery. It also designates U.S. federal district courts as the exclusive forum for Securities Act claims, subject to enforceability under Delaware law. These provisions do not apply to claims under the Exchange Act, which must be brought in federal court. These forum provisions may limit a stockholder’s ability to bring a claim in a forum they find favorable and could discourage lawsuits.

While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision. If a court determines these provisions are unenforceable, we could incur additional costs defending actions in multiple jurisdictions, which may adversely affect our business and financial condition.

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Future sales, or the perception of future sales, of our stock could lower our share price and dilute the holdings of our existing stockholders.

Sales of a substantial number of shares, or even the expectation of a future sale, could reduce our stock price and make it harder for us to raise capital on favorable terms. If these shares are sold, or if investors believe they will be sold, our stock price could decline. We may also issue additional shares in the future to raise capital or fund acquisitions. Any such issuance could significantly increase the number of shares outstanding, dilute current stockholders’ voting power, and negatively affect our stock price.

Stockholder activism could disrupt our business and harm our stock price.

We may face actions or proposals from activist stockholders that conflict with our business strategy or other stockholders’ interests. Responding to these activities can be costly, time-consuming, and distract management and the Board from running the business. Activism may also create uncertainty about our future direction, which could harm relationships with customers, suppliers, and employees, and make it harder to attract talent. If a proxy contest occurs, we could incur significant legal and solicitation expenses and management attention could be diverted. Activist campaigns may also lead to litigation, further increasing costs and disruption. These activities could negatively affect our ability to execute our strategic plan and cause our stock price to fluctuate. We have previously adopted, and may again in the future choose to adopt, a stockholder rights agreement, which, if adopted, could have certain anti-takeover effects.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Assessing, Identifying and Managing Cybersecurity Risks — We rely extensively on information technology (“IT”) and operational technology (“OT”) systems to support exploration, drilling, production, and administrative functions across our offshore and corporate operations. These systems include process control systems on production platforms, remote monitoring systems, and enterprise IT applications for finance, human resources, and supply chain management. Our cybersecurity program is designed to protect these systems from unauthorized access, data breaches, ransomware, and other cyber threats. We aim to implement industry-standard security measures including network segmentation, firewalls, intrusion detection, endpoint protection, multi-factor authentication, incident response plans, security awareness training, and regular security audits. In addition, we maintain policies and procedures designed to assess, identify and manage cybersecurity threats and incidents and strive to align our cybersecurity operating model with the National Institute of Standards and Technology Cybersecurity Framework (“NIST CSF”). We do not represent that our practices conform to any specific technical standards or requirements; rather, we utilize the NIST CSF as a framework that informs how we design our approach to identify, evaluate, and address cybersecurity risks in our operations. In November 2025, we appointed a Vice President - Chief Information Officer (“CIO”) to oversee our cybersecurity team, which actively works with third-party service providers to assess, identify and manage risks in our information systems in order to protect the confidentiality, integrity and availability of our digital infrastructure. The cybersecurity team meets regularly to evaluate potential threats, discuss best practices and identify new solutions to help mitigate cyber risks.

Our third-party service providers provide extended coverage of our information technology and operational technology environments and conduct regular evaluations of our cybersecurity controls, including testing the design and operational effectiveness of our cybersecurity controls. We also share and receive threat intelligence with other companies in the energy sector, government agencies, information sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment.

To serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through cybersecurity training, simulated phishing exercises and awareness campaigns. We routinely conduct employee training, and point-in-time training for any phishing failures. We have implemented software and processes and currently use a managed service to help identify and evaluate risks from cybersecurity threats associated with third-party service vendors. In the event of a cybersecurity incident deemed to have a moderate or higher business impact, we have an incident response plan to notify senior leadership and to address how to contain the incident, mitigate the impact, and restore normal operations efficiently.

Cybersecurity Risk Assessment — We have integrated cybersecurity risk management into our broader Enterprise Risk Management (“ERM”) framework to promote a company-wide culture of cybersecurity risk management. Our ERM framework is designed to identify and prioritize company-wide risks, including cybersecurity threats, and integrate mitigation measures into our business, operational and capital structure planning activities. The purpose of the ERM framework is to enable the Board and executive leadership to (1) align risk management with strategic objectives, (2) identify risks, including cybersecurity risks, throughout the organization, (3) assess and prioritize risks that could impact the Company’s operational and strategic objectives, (4) develop and monitor risk mitigation initiatives, and (5) report and assess material risks, mitigation strategies and progress to the Board and/or its applicable committees. Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program .

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Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk. The Audit Committee oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our cybersecurity team regularly updates and reports to the Audit Committee regarding cybersecurity risk exposure and our cybersecurity risk management strategy. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board. To further inform our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as applicable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards.

Management’s Role in Assessing and Managing Cybersecurity Threats — Our CIO is responsible for assessing, identifying and managing cybersecurity risks and is supported by the cybersecurity team. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. The CIO, who reports directly to the CFO and is a member of the ERM Steering Committee, is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure. Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO. In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed. Our CIO has over 30 years of experience in information technology and cybersecurity, holds a Bachelor of Science from Royal Holloway, University of London and has performed the role of CIO for over 7 years within a leading upstream E&P Company including the responsibility and accountability to the Audit Committee for cybersecurity.

Impact of Risks from Cybersecurity Threats — The energy sector’s growing reliance on information and operational technology to manage critical business functions has significantly increased the exposure to cybersecurity threats. The rising frequency and sophistication of cyber incidents, whether resulting from deliberate attacks or accidental breaches, pose substantial risks to the energy industry. For example, a cyber-attack on a production control system could result in significant environmental and safety risks, such as a well incident, shut-in or spill that could cause business interruption, reputational damage, regulatory fines and penalties, costs of compliance and remediation or insurance limitations. Other examples of cybersecurity threats we face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry. Our customers, suppliers, subcontractors and joint venture partners face similar cybersecurity threats. As these threats continue to evolve, effectively preventing, detecting, mitigating, and responding to cyber incidents has become an ongoing and increasingly complex challenge. Regulatory compliance adds another layer of complexity, particularly as cybersecurity reporting and disclosure requirements continue to evolve. These regulations require prompt and detailed disclosures of material cyber incidents, demanding significant resources and well-structured internal processes to maintain compliance. Failure to meet these obligations could lead to legal penalties, heightened regulatory oversight, and reputational harm. Additionally, the constantly shifting regulatory landscape may introduce overlapping or conflicting requirements, further complicating compliance efforts. To minimize potential risks, it is essential to closely monitor these developments and incorporate them into our cybersecurity and regulatory compliance strategies.

As of the date of this Annual Report, we are not aware of any cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company periodically experiences cybersecurity incidents that are not deemed material to our business. A significant cybersecurity incident impacting us or third parties with whom we do business could materially and adversely disrupt our operations and affect our business strategy and performance, financial condition and results of operations. Although we believe we have implemented comprehensive cybersecurity measures, no security program is infallible. For additional information about cybersecurity risks, please see Part I, Item 1A. Risk Factors — Risks Related to our Business and the Oil and Natural Gas Industry — Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

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On June 13, 2024, Equinor USA E&P Inc. (f/k/a Statoil USA E&P, Inc., and f/k/a Norsk Hydro USA Oil & Gas, Inc.) (“Equinor”) filed a complaint against Talos ERT LLC (“Talos ERT”) in the U.S. District Court for the Southern District of Texas, seeking to recover decommissioning and P&A expenses on a certain Gulf of America lease, Mississippi Canyon 941 (“MC 941 Lease”). Equinor’s claim rests upon a purported indemnity set forth in a 2006 conveyance instrument in which a former affiliate of Equinor, Hydro Gulf of Mexico, LLC (“Hydro GOM”), sold a 25% interest in the MC 941 Lease to Energy Resource Technology GOM, Inc. (“ERT”) (n/k/a Talos ERT). That 25% lease interest was then conveyed to ATP Oil & Gas, Inc. a few months later. The interest was sold several times thereafter, including in 2017, when Equinor reacquired 100% of the MC 941 Lease. Production is continuing from the MC 941 Lease, and as a result, Equinor is seeking decommissioning costs not yet incurred and thus for unknown and unspecified amounts. On September 23, 2024, Talos ERT filed an answer denying all material allegations in Equinor’s complaint and asserting a counterclaim for declaratory relief. Talos ERT’s counterclaim relies upon indemnities provided pursuant to subsequent transactions of the 25% interest, which Talos ERT asserts Equinor assumed directly or owes as burdens running with the land that it acquired. Talos ERT’s counterclaim seeks a declaration that Equinor owes Talos ERT reimbursements for all decommissioning costs and Talos ERT’s legal fees in the litigation. On January 10, 2025, Equinor amended its complaint, expanding the scope of the alleged decommissioning obligations to include the Titan floating platform that was placed on location at the MC 941 Lease, years after ERT sold its interest in the MC 941 Lease in 2006, and the full cost to plug and abandon all wells on the MC 941 Lease. Talos ERT will continue to vigorously defend against Equinor’s claims and pursue its counterclaim. The trial is currently scheduled for 2026 but may be continued until 2027.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone Energy Corporation (“Stone”) and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in these three lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In 2018, the Jefferson Parish lawsuits were removed to the United States District Court for the Eastern District of Louisiana. Plaintiffs filed motions to remand the cases back to state court, which were granted by the federal district court on December 13, 2023. The defendants that filed the removals have appealed the orders of remand. Since the remands to state court, the three Jefferson Parish state court cases involving Stone have been relatively dormant. Only one of these cases has been set for trial, for the October-November 2027 docket.

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In state court, the Plaquemines Parish lawsuit was stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. However, in 2018, the Plaquemines Parish lawsuit was removed to the United States District Court for the Eastern District of Louisiana (the “District Court”). The plaintiffs moved to remand the lawsuit to the state courts, but the case was administratively closed in federal court pending the appeal of another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. That appeal was resolved by the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. Plaintiffs filed motions to remand, which the District Court granted. The defendants that filed the removal have appealed the order of remand. Since the remand to state court, this case has been relatively dormant and has not been set for trial.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for more information.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities

Market for Common Stock

Our common stock is listed on the NYSE under the symbol “TALO”.

Holders of Record

Pursuant to the records of our transfer agent, as of February 17, 2026, there were approximately 133 holders of record of our common stock.

Dividends

We have never declared or paid any cash dividends on our common stock, and we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the near-term. Although we do not expect to pay dividends on our common stock, if our Board of Directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions that the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information.

Securities Authorized for Issuance Under Equity Compensation Plans

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth information with respect to our repurchase of shares of common stock during the three months ended December 31, 2025 (in thousands, except for the share and per share amounts):

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Period

Total Number of Shares Purchased

 

Average Price Paid

 

Total Number of Shares Purchased as Part of Publicly Announced Program(1)

 

Approximate Dollar Values of Shares that May Yet be Purchased Under the Program

 

October 1, 2025- October 31, 2025

 

—

 

$

—

 

 

—

 

$

97,330

 

November 1, 2025- November 30, 2025

 

159,571

 

$

10.97

 

 

159,571

 

$

95,580

 

December 1, 2025- December 31, 2025

 

1,330,000

 

$

11.05

 

 

1,330,000

 

$

80,889

 

Total

 

1,489,571

 

$

11.04

 

 

1,489,571

 

 

 

 

(1) Refer to Part I, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information regarding our authorized share repurchase program.

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Stockholder Return Performance Presentation

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for December 31, 2020 through December 31, 2025. The graph assumes that $100 was invested in our common stock and each index on December 31, 2020 and that dividends were reinvested.

img251216048_2.gif

 

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2020

 

2021

 

2022

 

2023

 

2024

 

2025

 

Talos Energy Inc.

$

100

 

$

119

 

$

229

 

$

173

 

$

118

 

$

134

 

S&P 500 Index

$

100

 

$

129

 

$

105

 

$

133

 

$

166

 

$

196

 

Dow Jones U.S. Exploration & Production Index

$

100

 

$

176

 

$

280

 

$

291

 

$

288

 

$

295

 

The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.

Item 6. [Reserved]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements.

This section of this Annual Report generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 27, 2025.

Our Business

We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our Upstream business in the U.S. Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and reserve recovery, safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.

Outlook

In 2026, we anticipate continued commodity price uncertainty, evolving global macroeconomic conditions, regulatory pressures, and shifting external expectations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Fluctuating commodity prices will directly affect our revenues.

We intend to prioritize high-margin oil production in 2026 underpinned by balanced investment in infrastructure-led development, exploration and appraisal, and multi-well development as part of the Monument Project. Capital expenditures guidance for 2026 is expected to range from $500 to $550 million. Abandonment and decommissioning expenditures are expected to range from $100 to $130 million. Non-operated capital expenditures are expected to be 40% of capital expenditures, which is an increase year over year and largely driven by the Monument Project. Approximately 10% of capital expenditures will be allocated to exploration. Production for 2026 is expected to be in the range of 62 to 66 MBopd; 85 to 90 MBoepd.

Tropical Storm Risk’s extended outlook for the 2026 Atlantic hurricane season indicates activity in line with long‑term averages—14 named storms, 7 hurricanes, and 4 major hurricanes. We incorporate expected weather‑related downtime into our operational and financial planning to maintain flexibility and support achievement of production objectives.

Operational Update

CPN — During the first quarter of 2026, we successfully drilled the CPN well with first production expected in the second half of 2026. The CPN well will tie back to our non-operated Na Kika facility. Talos is the operator of CPN and holds a 65% working interest.

Katmai — The Katmai #2 well came online in the second quarter of 2025. The Katmai Field ties back to our operated Tarantula facility. In connection with the Katmai #2 well coming online, the Tarantula gross processing capacity was expanded to 35 MBoepd to accommodate higher volumes. During the fourth quarter of 2025, gross processing capacity at the Tarantula facility was increased to approximately 38 MBoepd. Talos is the operator of the Katmai Field and holds a 50% working interest.

Genovesa — During the fourth quarter of 2025, we temporarily shut-in production from the Genovesa well, which ties back to the non-operated Na Kika facility, due to a failure of the surface-controlled subsurface safety valve resulting in deferred production of approximately 3 MBoepd. We expect the Genovesa well to return to production in the third quarter of 2026 following completion of a planned workover. Talos is the operator of Genovesa and holds a 65% working interest.

Cardona — We successfully drilled and completed the Cardona well in late 2025. Production from the Cardona well ties back to our Pompano facility. Talos is the operator and holds a 65% working interest.

Manta Ray — During the fourth quarter of 2025, we participated in the drilling of the non-operated Manta Ray well. While the well encountered hydrocarbons, it was deemed non-commercial. Talos held a 40% working interest.

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Daenerys — In August 2025, we announced successful drilling results at the Daenerys exploration prospect located on Walker Ridge blocks 106, 107, 150 and 151. The discovery well has been temporarily suspended to preserve its future utility. We plan to spud an appraisal well during the second quarter of 2026 to further define the discovered resource. Talos is the operator of Daenerys and holds a 27% working interest.

Recent Developments

The following encompasses recent developments since the filing of our Annual Report on Form 10-K for year ended December 31, 2024:

Amended and Restated Credit Agreement — On January 20, 2026, we entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) with a syndicate of financial institutions as lenders and JPMorgan Chase Bank, N.A. as administrative agent. The initial borrowing base and the total commitments are each $700 million. The A&R Credit Agreement replaces the Company’s amended credit agreement dated May 10, 2018. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

Lease Sale — The Big Beautiful Gulf 1 lease sale was held by BOEM on December 10, 2025. It was the first offshore oil and gas lease sale conducted under the new OBBBA. We emerged as the apparent high bidder on eleven of the twelve lease blocks on which we bid. As of February 17, 2026, we have been awarded eight of the lease blocks for which we were the high bidder and are awaiting BOEM’s award decisions on our remaining high bids.

Surety Arrangements and Collateral Requirements — In early November 2025, we entered into various collateral funding and security arrangements (“CFSAs”) to establish limits on the amount of aggregate collateral that our surety providers can require us to post. In exchange for our agreement to post the required amounts of collateral through July 1, 2031 and spend at least a specified amount on annual plugging and abandonment activities each year through 2030, the surety providers agreed not to (1) require additional collateral in excess of the agreed and scheduled amounts on existing surety bonds; (2) draw on collateral posted for the benefit of the sureties except under limited circumstances; (3) seek remedies for breaches of any surety agreement that are not an “Event of Default” as defined in the primary CFSA; or (4) cancel, or attempt to cancel, existing bonds unless requested by us.

For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, we are required to spend $90.0 million and $45.0 million on plugging and abandonment activities on an annual basis, respectively. As of December 31, 2025, our aggregate estimated collateral funding commitments under the CFSAs were $251.7 million through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies— Performance Obligations” for the estimated collateral funding commitments by year under the CFSAs. Also, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Market Outlook.”

The CFSAs generally contain certain events of default which, if triggered and not cured by us within the cure period, would terminate the standstill period and provide the sureties their full rights under their respective surety and indemnity agreements, including the right to call collateral. Events of default include, but are not limited to, the failure to maintain liquidity of $200.0 million or above a specified credit rating. However, if an event of default were to occur, it is anticipated we would be in a similar position than if we had not entered into the CFSAs given that the surety providers already have the right to demand collateral under existing surety bonds.

The CFSAs provide a multi-year framework to efficiently address the Company’s collateral commitments and abandonment activities, while strengthening the relationship with our surety providers and supporting our long-term operational strategy.

Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. Prior to this acquisition, we owned an interest in and operated these developed and producing blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Enhanced Corporate Strategy — On June 17, 2025, we announced an enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The strategy is built on three key pillars. The first pillar targets increased annualized free cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements. The second pillar focuses on growth through high-margin organic projects and selective Deepwater acquisitions. The third pillar aims to build a long-lived and scaled portfolio in the U.S. Gulf of America and potentially other conventional basins. This strategy is underpinned by a disciplined capital allocation framework which prioritizes investing in projects expected to generate robust returns through commodity cycles, returning cash to shareholders, maintaining a strong balance sheet, and growing through selective opportunities.

Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board of Directors (the “Board”) that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer was appointed by the Board. On August 12, 2025,

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the Board appointed Mr. Zachary B. Dailey to serve as the Company’s Executive Vice President and Chief Financial Officer and principal financial officer, effective August 18, 2025.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Appointment of President and Chief Executive Officer — Effective March 1, 2025, Mr. Paul Goodfellow was appointed President and Chief Executive Officer, principal executive officer and as an executive member of the Board.

Share Repurchase Program — During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board, resulting in $80.9 million available under the share repurchase program. See “Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

QuarterNorth Acquisition — On March 4, 2024, we completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

During the year ended December 31, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.2 MBoepd for the year ended December 31, 2024 based on production rates prior to the shut in. The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile and have remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, oil, natural gas and NGL prices have been, and may continue to be, subject to wide fluctuations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices, and sustained lower prices could adversely affect our financial results. We use hedging instruments to reduce the impact of near-term price volatility. We also anticipate continuing to operate our business in a volatile market by prioritizing high-return development projects, focusing on cost control measures, and maintaining a strong balance sheet to provide financial, operational and capital spending flexibility under a range of price scenarios. We continue to monitor commodity price trends closely and will modify our plans within our strategy as appropriate. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2025.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production.

Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and may not adjust downward as fast as oil prices do. Inflation may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

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In 2025, the Federal Reserve cut interest rates three times, most recently in December, bringing the federal funds rate down to a target range of 3.50%–3.75%. These cuts mark the lowest rates since 2022. Future changes to the benchmark interest rate remain uncertain.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2025, our ceiling test calculations resulted in an impairment of our oil and natural gas properties of $454.5 million. During 2024 and 2023 our ceiling test computations for our U.S. oil and gas properties did not result in an impairment. At December 31, 2025, the Company’s ceiling test computation was based on SEC pricing of $65.37 per Bbl of oil, $3.61 per Mcf of natural gas and $19.22 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $58.76 per Bbl of oil, $3.26 per Mcf of natural gas and $17.35 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

Financial Assurance Requirements — On April 15, 2024, BOEM issued a final rule related to supplemental financial assurance requirements in the OCS entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” This rule significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “Western Louisiana District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The Western Louisiana District Court granted a stay of the litigation while BOEM pursues efforts to suspend, revise, or rescind the final rule. The Western Louisiana District Court’s order temporarily limits full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.

On May 2, 2025, the DOI announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s former policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required, and if so, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.

Notwithstanding the status of the final rule or a new revised rule, BOEM stated it will continue to require lessees on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of their decommissioning liabilities.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

Financial Assurance Market Outlook — As a result of adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of surety companies have left the offshore surety market, which has materially reduced the availability of surety bonds for projects in the OCS and may reduce the ability of companies operating in the OCS to obtain bonding without posting collateral. As a result, there may not be sufficient surety bond capacity available for companies in the OCS to comply with BOEM’s financial assurance requirements or otherwise if the final rule is not suspended, revised or rescinded or if it is not overturned pursuant to the ongoing litigation. In addition to BOEM’s financial assurance requirements, companies with whom we partner or from whom we wish to acquire assets may require that we provide financial assurance, such as surety bonds, to provide assurance that our decommissioning obligations associated with those jointly held or acquired assets can be met in the future. The tightened capacity in the surety market may impact our ability to secure surety bonds at commercially reasonable terms and therefore, our ability to enter into such joint participation or asset acquisition opportunities may be impacted.

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In early November 2025, we entered into CFSAs to establish limits on the amount of aggregate collateral that our surety providers can require us to post through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information.

Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of America. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

Hurricanes, Tropical Storms, Winter Storms and Loop Currents — Since our operations are in the U.S. Gulf of America, we are particularly vulnerable to the effects of hurricanes, tropical storms, winter storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues and increased lease operating expenses for evacuations and repairs.

Future Offshore Leasing — Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“Withdrawal Memoranda”) under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.

On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s Withdrawal Memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts. On October 2, 2025, the Western District Court of Louisiana found in part for the plaintiffs challenging the Withdrawal Memoranda, which included the States of Louisiana, Alaska, Georgia and Mississippi, the Gulf Energy Alliance and the American Petroleum Institute, and ruled that the Withdrawal Memoranda are unlawful because they exceed the authority granted to the President under OCSLA. The challenge to President Trump’s revocation of the Withdrawal Memoranda remains ongoing.

Earlier in 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. In June 2025, the comment period closed regarding BOEM’s notice requesting information and comments on the preparation of the 11th National OCS Program. On November 24, 2025, BOEM announced the availability of a draft proposed program (“DPP”) for OCS oil and gas leasing for the 2026-2031 period. The 2026-2031 DPP proposes a schedule of 34 OCS oil and gas lease sales during this five-year period, which includes 7 lease sales in the Gulf of America. These would be in addition to offshore oil and gas lease sales mandated by law outside the five-year program. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.

The OBBBA, signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%. On August 19, 2025, the DOI announced the schedule for the 30 OBBBA-mandated Gulf of America lease sales, the first of which, named the Big Beautiful Gulf 1 Lease Sale was held on December 10, 2025. This lease sale took the place of the previously announced Lease Sale 262, which had been deferred by BOEM. The remaining lease sales are expected to be held each March and August for the years 2026 through 2039, with the last of these mandated Gulf of America lease sales expected in March 2040. On February 4, 2026, BOEM announced its Final Notice of Sale for the Big Beautiful Gulf 2 Lease Sale, which is scheduled to be held on March 11, 2026.

Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations.

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Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion — In August 2024, the federal district court for the District of Maryland vacated the 2020 Biological Opinion issued by the NMFS, related to oil and gas activities in the Gulf of America. The vacatur was initially effective December 20, 2024, but was later extended to May 21, 2025. On May 20, 2025, NMFS published its new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. On the same day, two lawsuits were filed opposing the new Biological Opinion, one by several environmental groups (Sierra Club, the Center for Biological Diversity, Friends of the Earth and Turtle Island Restoration Network) who filed in the federal district court for the District of Maryland, and the other by the State of Louisiana, the API and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. Both lawsuits seek declaratory and injunctive relief. On January 23, 2026, the Western Louisiana District Court judge issued a summary judgment in favor of the State of Louisiana, API and Chevron U.S.A. Inc., and found the 2025 Biological Opinion unlawful. The 2025 Biological Opinion was remanded, without vacatur, to NMFS to correct the Biological Opinion’s deficiencies. The 2025 Biological Opinion will remain active to avoid disruptive consequences to regulated parties. The outcome of the environmental groups’ challenge in the Maryland District Court remains uncertain at this time.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Oil

 

88

 %

 

92

 %

 

93

 %

Natural gas

 

10

 %

 

5

 %

 

5

 %

NGL

 

2

 %

 

3

 %

 

2

 %

 

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of America basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

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In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Oil:

 

 

 

 

 

 

NYMEX WTI high per Bbl

$

75.74

 

$

85.35

 

$

89.43

 

NYMEX WTI low per Bbl

$

57.97

 

$

69.95

 

$

70.25

 

Average NYMEX WTI per Bbl

$

65.45

 

$

76.54

 

$

77.63

 

Average oil sales price per Bbl (including commodity derivatives)

$

68.18

 

$

75.07

 

$

73.59

 

Average oil sales price per Bbl (excluding commodity derivatives)

$

64.84

 

$

75.01

 

$

75.17

 

Natural Gas:

 

 

 

 

 

 

NYMEX Henry Hub high per MMBtu

$

4.26

 

$

3.18

 

$

3.27

 

NYMEX Henry Hub low per MMBtu

$

2.91

 

$

1.49

 

$

2.14

 

Average NYMEX Henry Hub per MMBtu

$

3.53

 

$

2.19

 

$

2.54

 

Average natural gas sales price per Mcf (including commodity derivatives)

$

3.70

 

$

2.65

 

$

3.32

 

Average natural gas sales price per Mcf (excluding commodity derivatives)

$

3.67

 

$

2.57

 

$

2.60

 

NGLs:

 

 

 

 

 

 

NGL realized price as a % of average NYMEX WTI

 

28

 %

 

27

 %

 

23

 %

 

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our A&R Credit Agreement and Hedging Policy and may be different from what we have done on a historical basis.

Expenses

Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain reimbursements for costs from certain third parties.

Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to plug, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

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General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.

Interest Expense — We may finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our bank credit facility and term-based debt. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Results of Operations

Revenues

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

 

 

2025

 

2024

 

Change

 

Revenues:

 

 

 

 

 

 

Oil

$

1,560,401

 

$

1,806,148

 

$

(245,747

)

Natural gas

 

169,445

 

 

105,528

 

 

63,917

 

NGL

 

50,224

 

 

61,892

 

 

(11,668

)

Total revenues

$

1,780,070

 

$

1,973,568

 

$

(193,498

)

 

 

 

 

 

 

 

Production Volumes:

 

 

 

 

 

 

Oil (MBbls)

 

24,065

 

 

24,078

 

 

(13

)

Natural gas (MMcf)

 

46,122

 

 

41,078

 

 

5,044

 

NGL (MBbls)

 

2,782

 

 

2,969

 

 

(187

)

Total production volume (MBoe)

 

34,534

 

 

33,893

 

 

641

 

 

 

 

 

 

 

 

Daily Production Volumes by Product:

 

 

 

 

 

 

Oil (MBblpd)

 

65.9

 

 

65.8

 

 

0.1

 

Natural gas (MMcfpd)

 

126.4

 

 

112.2

 

 

14.2

 

NGL (MBblpd)

 

7.6

 

 

8.1

 

 

(0.5

)

Total production volume (MBoepd)

 

94.6

 

 

92.6

 

 

2.0

 

 

 

 

 

 

 

 

Average Sale Price per Unit:

 

 

 

 

 

 

Oil (per Bbl)

$

64.84

 

$

75.01

 

$

(10.17

)

Natural gas (per Mcf)

$

3.67

 

$

2.57

 

$

1.10

 

NGL (per Bbl)

$

18.05

 

$

20.85

 

$

(2.80

)

Price per Boe

$

51.55

 

$

58.23

 

$

(6.68

)

Price per Boe (including realized commodity derivatives)

$

53.90

 

$

58.37

 

$

(4.47

)

 

The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment, due to changes in sales prices and production volumes (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Price

 

Volume

 

Total

 

Revenues:

 

 

 

 

 

 

Oil

$

(244,772

)

$

(975

)

$

(245,747

)

Natural gas

 

50,954

 

 

12,963

 

 

63,917

 

NGL

 

(7,769

)

 

(3,899

)

 

(11,668

)

Total revenues

$

(201,587

)

$

8,089

 

$

(193,498

)

 

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Volumetric Analysis — Production volumes increased by 2.0 MBoepd to 94.6 MBoepd for the year ended December 31, 2025. The increase was primarily due to 6.4 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there were increases of 2.3 MBoepd and 1.2 MBoepd of production from our Katmai West #2 and Sunspear wells, respectively, both of which commenced initial production in June 2025. Production volumes also increased 2.0 MBoepd due to the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by 10.6 MBoepd related to natural decline of the production rate of existing oil and natural gas wells. The absence of weather-related downtime during the 2025 hurricane season compared to the same period in 2024 was favorable to our production volumes.

Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Lease operating expenses

$

546,716

 

$

566,041

 

Lease operating expenses per Boe

$

15.83

 

$

16.70

 

 

Total lease operating expenses for the year ended December 31, 2025 decreased by approximately $19.3 million, or 3%. The decrease is primarily related to a $40.2 million decrease in facility and workover expenses primarily related to the HP-1 dry dock and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $16.9 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter 2024.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Depreciation, depletion and amortization

$

1,056,281

 

$

1,023,558

 

 

Depreciation, depletion and amortization expense for the year ended December 31, 2025 increased by approximately $32.7 million, or 3%. This increase was primarily driven by increased production volumes of 2.0 MBoepd discussed above.

General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Upstream Segment

$

155,368

 

$

191,063

 

CCS Segment

 

—

 

 

10,454

 

Total general and administrative expense

$

155,368

 

$

201,517

 

 

 

 

 

 

Upstream general and administrative expense per Boe

$

4.50

 

$

5.64

 

 

General and administrative expense for the year ended December 31, 2025, decreased by approximately $46.1 million, or 23%. This decrease was primarily driven by Upstream Segment transactions costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $46.6 million or $2.65 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. This decrease was partially offset by an increase in non-cash equity-based compensation of $4.0 million compared to the same period in 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Share Based Compensation for additional information.

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Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Accretion expense

$

125,296

 

$

117,604

 

Impairment of oil and natural gas properties

$

454,482

 

$

—

 

Other operating (income) expense

$

1,789

 

$

(109,454

)

Interest expense

$

163,381

 

$

187,638

 

Price risk management activities (income) expense

$

(105,455

)

$

1,458

 

Equity method investment (income) expense

$

1,807

 

$

10,289

 

Other (income) expense

$

(15,520

)

$

44,930

 

Income tax (benefit) expense

$

(109,169

)

$

5,003

 

 

Accretion Expense — During the year ended December 31, 2025, we recorded $125.3 million of accretion expense compared to $117.6 million during the year ended December 31, 2024. The change is primarily the result of a $4.4 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition combined with a higher asset retirement obligation subject to accretion expense. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Impairment of oil and natural gas properties — During the year ended December 31, 2025, we recorded a $454.5 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment.

Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Interest Expense — During the year ended December 31, 2025, we recorded $163.4 million of interest expense compared to $187.6 million during the year ended December 31, 2024. The change is primarily due to a $19.2 million decrease in interest expense related to the Bank Credit Facility as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Price Risk Management Activities — The income of $105.5 million for the year ended December 31, 2025 consisted of $81.5 million in cash settlement gains and $24.0 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains.

These unrealized gains and losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2026, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.

Equity Method Investment (Income) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million, of which $8.0 million related to our CCS Segment that was divested in March 2024.

Other (Income) Expense — During the year ended December 31, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

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Income Tax Benefit (Expense) — During the year ended December 31, 2025, we recorded $109.2 million of income tax benefit compared to $5.0 million of income tax expense during the year ended December 31, 2024. The benefit of $109.2 million for the year ended December 31, 2025 is primarily due to current year activity offset with income tax expense of $28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets. For the year ended December 31, 2024, we recorded $5.0 million of income tax expense primarily related to state income tax expense of $17.7 million and an income tax benefit of $10.1 million related to current year activity inclusive of nontaxable or nondeductible items. See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Income Taxes.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information.

Supplemental Non-GAAP Measure

EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.

“EBITDA,” “Adjusted EBITDA,” and “Adjusted EBITDA attributable to Talos Energy Inc.” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc. have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

•
EBITDA — Net income (loss) attributable to Talos Energy Inc. plus net income (loss) attributable to noncontrolling interest, plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.
•
Adjusted EBITDA — EBITDA plus non-cash impairment of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash impairment of other well equipment and non-cash equity-based compensation expense.
•
Adjusted EBITDA attributable to Talos Energy Inc. — Adjusted EBITDA, less adjustments for noncontrolling interest.
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The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Net income (loss) attributable to Talos Energy Inc.

$

(494,290

)

$

(76,393

)

$

187,332

 

Net income (loss) attributable to noncontrolling interest

 

(1,034

)

 

—

 

 

—

 

Net income (loss)

 

(495,324

)

 

(76,393

)

 

187,332

 

Interest expense

 

163,381

 

 

187,638

 

 

173,145

 

Income tax (benefit) expense

 

(109,169

)

 

5,003

 

 

(60,597

)

Depreciation, depletion and amortization

 

1,056,281

 

 

1,023,558

 

 

663,534

 

Accretion expense

 

125,296

 

 

117,604

 

 

86,152

 

EBITDA

 

740,465

 

 

1,257,410

 

 

1,049,566

 

Impairment of oil and natural gas properties

 

454,482

 

 

—

 

 

—

 

Transaction and other (income) expense(1)

 

5,001

 

 

(59,022

)

 

(33,295

)

Decommissioning obligations(2)

 

3,245

 

 

8,559

 

 

11,879

 

Derivative fair value (gain) loss(3)

 

(105,455

)

 

1,458

 

 

(80,928

)

Net cash received (paid) on settled derivative instruments(3)

 

81,471

 

 

4,710

 

 

(9,457

)

(Gain) loss on debt extinguishment

 

—

 

 

60,256

 

 

—

 

Non-cash equity-based compensation expense

 

18,418

 

 

14,462

 

 

12,953

 

Adjusted EBITDA

$

1,197,627

 

$

1,287,833

 

$

950,718

 

 

(1)
For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation. Transaction expenses include $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture related to a 49.9% equity interest in Talos Mexico sold to Zamajal. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments.
(2)
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on decommissioning obligations.
(3)
The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our bank credit facility. Our primary uses of cash are for capital expenditures, operating costs, working capital, debt service, share repurchases, future collateral payments and for general corporate purposes. The cost of borrowing under our bank credit facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.

Our new bank credit facility currently has a borrowing base of $700.0 million. As of December 31, 2025, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $965.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. The next redetermination of our borrowing base is expected in the second quarter of 2026. The borrowing base in reserve-based lending, which is influenced by banking regulations and guidelines, is a dynamic figure subject to regular redeterminations. Changes in reserve estimations (e.g., lower production forecasts or reduced proved reserves), downward adjustments to the lender's internal price deck (i.e., commodity price expectations) and ongoing production can lead to a reduction in the borrowing base, impacting available liquidity under our bank credit facility. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

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We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the bank credit facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

Capital and Other Expenditures — The following is a table of our capital and other expenditures, excluding acquisitions, for the year ended December 31, 2025 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

U.S. drilling & completions

$

394,264

 

Asset management(1)

 

31,991

 

Seismic and G&G, land, capitalized G&A and other

 

67,812

 

Total capital expenditures

 

494,067

 

Plugging & abandonment

 

117,847

 

Decommissioning obligations settled(2)

 

1,102

 

Investment in Mexico

 

4,559

 

Total capital and other expenditures

$

617,575

 

 

(1)
Asset management consists of capital expenditures for development related activities primarily associated with recompletions and improvements to our facilities and infrastructure.
(2)
Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on decommissioning obligations.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under our bank credit facility, provide sufficient liquidity to fund our 2026 capital spending program of $500.0 million to $550.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $130.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under our bank credit facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

Surety Agreements and Collateral Requirements — The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information on estimated collateral funding commitments under the CFSAs. The collateral requirements may be secured by cash or letters of credit which will reduce our liquidity.

Common Stock Repurchase Program — Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $80.9 million remaining under the authorized program as of December 31, 2025. During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 20.0 million shares under our authorized program for a total amount of $211.6 million, exclusive of broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. Our share repurchase program is subject to the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations.

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Operating activities

$

935,826

 

$

962,593

 

Investing activities

$

(546,746

)

$

(1,320,279

)

Financing activities

$

(164,522

)

$

436,119

 

 

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Operating Activities — Net cash provided by operating activities decreased $26.8 million in 2025 compared to 2024. The change between periods is primarily attributable to an $80.9 million increase in cash from earnings after non-cash items, as presented in the Consolidated Statements of Cash Flows under Part IV, Item 15. Exhibits and Financial Statement Schedules, offset by a $9.1 million increase in settlement of asset retirement obligations. There was a $98.6 million decrease in cash due to changes in working capital accounts across all categories of operating assets and liabilities. Working capital at any specific point in time is subject to many variables, including commodity prices, production volumes, and the timing of cash receipts and payments.

Investing Activities — Net cash used in investing activities decreased $773.5 million in 2025 compared to 2024. Payments for acquisitions (net of cash acquired) decreased by $886.2 million. During the year ended December 31, 2024, payment for acquisitions was $936.2 million, of which $916.0 million related to the QuarterNorth Acquisition. During the year ended December 31, 2025, payment for acquisitions was $50.0 million. Proceeds from the sale of businesses decreased by $146.7 million, all of which is attributable to the TLCS Divestiture. Additionally, contributions to equity method investees decreased by $18.4 million primarily attributable to the TLCS Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information on the QuarterNorth Acquisition and the TLCS Divestiture.

Financing Activities — Net cash provided by financing activities increased $600.6 million in 2025 compared to 2024. During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. During the year ended December 31, 2025, we repurchased $119.5 million of our common stock through our common stock repurchase program compared to $45.2 million in the corresponding period in 2024 both amounts inclusive of broker commissions. See subsection above entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Furthermore, the Bank Credit Facility had no activity during the year ended December 31, 2025 compared to net repayments of $200.0 million during the corresponding period in 2024.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2025, total debt, net of discount and deferred financing costs, was approximately $1,226.2 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2025. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Bank Credit Facility — We maintained a Bank Credit Facility with a syndicate of financial institutions. The borrowing base was redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we delivered to the administrative agent of our Bank Credit Facility. As discussed above under “— Recent Developments,” the A&R Credit Agreement replaced the Bank Credit Facility in January 2026. For additional details on our Bank Credit Facility and the A&R Credit Agreement, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 12.00% Second-Priority Senior Secured Notes—due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Redemption of the 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

9.000% Second-Priority Senior Secured Notes—due February 2029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenture. The 9.000% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1.

9.375% Second-Priority Senior Secured Notes—due February 2031 — The 9.375% Notes were issued pursuant to the 9.375% Notes indenture. The 9.375% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1.

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Material Cash Requirements — We are party to various contractual obligations. The following discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2025:

Debt — We have two separate principal payments of $625.0 million each, corresponding to two different series of notes maturing in February 2029 and February 2031 with fixed interest rates of 9.000% and 9.375%, respectively. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Our estimated interest payments associated with our debt is $525.5 million, of which $119.9 million is due within the next twelve months.

Vessel commitments — We have $42.9 million in vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs. These vessel commitments do not extend beyond a one-year period.

Operating lease obligations — See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information.

Finance lease — We have $67.6 million in commitments related to our lease agreement for the HP-1 floating production facility in the Phoenix Field, which is utilized in our oil and natural gas development activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information, which contemplates renewal period that we are reasonably certain to exercise.

Firm transportation commitments — We have agreements in place with pipeline carriers for future transportation of oil and gas production. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information.

Plugging and Abandonment — We have arrangements with our surety providers which require us to spend at least a specified amount on plugging and abandonment activities each year. For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029,we are required to spend $90.0 million and $45.0 million on these activities on an annual basis, respectively. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information.

Performance Obligations — As of December 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the carrying value of our proved oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.

Our proved oil, natural gas and NGL reserves are estimated in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

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Estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2025 and 2024 were fully engineered by NSAI and audited by them at December 31, 2023. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2025 would have increased by an estimated $110.8 million.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during the year ended December 31, 2025 of $454.5 million. If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells and remove or appropriately abandon all production facilities, structures and pipelines following cessation of operations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs decommissioning costs in an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Income Taxes — Our provision for income taxes includes U.S. federal and state and non-U.S. taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

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The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

Recently Adopted Accounting Standards

Information on Recently Adopted Accounting Standards that impacted our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

Recently Issued Accounting Standards

Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are primarily exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production.

We are subject to a minimum hedging requirement under our A&R Credit Agreement for each calendar month on a six-full fiscal quarter rolling basis. For any quarter occurring during the first four forward fiscal quarters, we are required to hedge a minimum of 50% of our reasonably anticipated projected production from proved developed producing reserves from the semi-annual reserves report delivered to the administrative agent of our A&R Credit Agreement, adjusted to 45% in July and November and 25% in August, September and October. For the fifth and sixth forward fiscal quarters, if the Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) is greater than or equal to 1.00 to 1.00, then we are required to hedge a minimum of 25%, adjusted to 20% in August, September and October.

All derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded as “Price risk management activities income (expense)” on the Consolidated Statements of Operations in each period.

Commodity Price Risks

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During year ended December 31, 2025, our average oil price realizations after the effect of derivatives decreased 9% to $68.18 per Bbl from $75.07 per Bbl in the comparable 2024 period. Our average natural gas price realizations after the effect of derivatives increased 40% during the year ended December 31, 2025 to $3.70 per Mcf from $2.65 per Mcf in the comparable 2024 period.

Price Risk Management Activities

Historically, we have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production primarily through the use of oil and natural gas swaps and costless collars. These contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

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We had commodity derivative instruments in place to reduce the price risk associated with future production of 7,371 MBbls of crude oil and 10,465 MMBtu of natural gas at December 31, 2025, with a net derivative asset position of $47.7 million. For additional information regarding our commodity derivative instruments, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments, included elsewhere in this Annual Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2025 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + +

 

 

 

Oil and Natural Gas Derivatives

 

 

 

 

Ten Percent Increase

 

Ten Percent Decrease

 

 

Fair Value

 

Fair Value

 

Change

 

Fair Value

 

Change

 

Price impact(1)

$

47,712

 

$

9,629

 

$

(38,083

)

$

88,273

 

$

40,561

 

 

(1)
Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

Variable Interest Rate Risks

We had total debt outstanding of $1,250.0 million at December 31, 2025, before unamortized original issue discount and deferred financing costs from our 9.000% Notes and 9.375% Notes, which bears interest at a fixed rate. There were no outstanding borrowings under our Bank Credit Facility with variable interest rates. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. As of December 31, 2025, our interest rate risk exposure is mitigated as a result of fixed interest rates on 100% of our debt. For additional information regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt, included elsewhere in this Annual Report.

We are subject to the risk of changes in interest rates under our bank credit facility. In addition, the terms of our A&R Credit Agreement require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base.

Item 8. Financial Statements and Supplementary Data

See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024 and 2023, included in Part IV, Item 15. Exhibits and Financial Statements Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Based on such evaluation, our chief executive officer and chief financial officer have concluded that as of December 31, 2025, our disclosure controls and procedures were effective at a reasonable assurance level.

Our disclosure controls and procedures are designed at a reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of SEC, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on the assessment, management has concluded that its internal control over financial reporting was effective as of December 31, 2025 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Our independent registered public accounting firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over financial reporting, which is included in this Annual Report.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

During the three months ended December 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.

Our Board of Directors has adopted a Code of Conduct applicable to all officers, directors and employees, which is available on our website (www.talosenergy.com) under “Governance Documents” section within the “Governance” tab. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Conduct by posting such information on the website address and location specified above.

The Company has an Insider Trading Policy governing the purchase, sale and other dispositions of the Company's securities that applies to the Company and its directors, officers and employees. The Company believes that its Insider Trading Policy is reasonably designed to promote compliance with insider trading laws, rules and regulations, and listing standards applicable to the Company. A copy of the Company's Insider Trading Policy is included as Exhibit 19.1 to this Annual Report.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated by reference to our Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)
The following documents are filed as part of this Annual Report:
(1)
Financial Statements:

Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements filed as part of this Annual Report on Form 10-K.

(2)
Financial Statement Schedules:

Other than as stated on the Index to Consolidated Financial Statements on page F-1 with respect to Schedule I, financial statement schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our Consolidated Financial Statements and related notes.

(3)
Exhibits:

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

Exhibit

Number

Description

 

 

 

2.1#

 

Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC EnVen Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

 

 

 

2.2#

 

Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).

 

 

 

3.1

 

Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

 

 

 

3.2

 

Certificate of Amendment of the Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on May 23, 2024).

 

 

 

3.3

 

Certificate of Designations of Series A Junior Participating Preferred Stock of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 1, 2024).

 

 

 

3.4

 

Certificate of Elimination of Certificate of Designations of Series A Junior Participating Preferred Stock of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024).

 

 

 

3.5

 

Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

 

 

 

4.1

 

Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.10 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on March 1, 2023).

 

 

 

4.2

 

Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

 

 

 

4.3

 

Indenture, dated as of February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (9.000% Senior Notes). (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

 

 

 

4.4

 

First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.000% Senior Notes) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).

 

 

 

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+

 

+
+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

4.5

 

Indenture, dated as of February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, (9.375% Senior Notes) (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

 

 

 

4.6

 

First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.375% Senior Notes) (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).

 

 

 

4.7

 

Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.5 hereto) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

 

 

 

4.8

 

Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A to Exhibit 4.6 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

 

 

 

4.9

 

Amended and Restated Credit Agreement, dated as of January 20, 2026, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K12 (File No. 001-38497) filed with the SEC on January 22, 2026).

 

 

 

10.1

 

Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B (File No. 001-38497) filed with the SEC on May 16, 2018).

 

 

 

10.2†

 

Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

 

 

 

10.3†

 

Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss, III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

 

 

 

10.4†

 

Separation and Release Agreement by and between the Company and Robert D. Abendschein, effective December 26, 2023 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 29, 2023).

 

 

 

10.5†

 

Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K12B (File No. 001-38497) filed with the SEC on May 16, 2018).

 

 

 

10.6†

 

Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on May 23, 2024).

 

 

 

10.7

 

Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018).

 

 

 

10.8†

 

Form of Indemnification Agreement (Directors and Officers) (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

 

 

 

10.9†

 

Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 9, 2018).

 

 

 

10.10†

 

Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

 

 

 

10.11†

 

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 3, 2021).

 

 

 

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+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

10.12†

 

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).

 

 

 

10.13†

 

Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).

 

 

 

10.14†

 

Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

 

 

 

10.15†

 

Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).

 

 

 

10.16†

 

Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 9, 2023).

 

 

 

10.17†

 

Form of Separation and Release Agreement (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 7, 2024).

 

 

 

10.18†

 

Separation and Release Agreement by and between Talos Energy Inc. and Timothy S. Duncan, effective November 1, 2024 (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on November 4, 2024).

 

 

 

10.19†

 

 

Performance Share Unit Grant Notice and Performance Share Unit Agreement by and between Talos Energy Inc. and Timothy S. Duncan, effective November 1, 2024 (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on November 4, 2024).

 

 

 

10.20

 

Cooperation Agreement, dated December 16, 2024, by and between Talos Energy Inc. and Control Empresarial de Capitales, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024).

 

 

 

10.21

 

 

Amendment to Cooperation Agreement effective as of December 8, 2025, by and between Talos Energy, Inc. and Control Empresarial de Capitales, S.A. de C.V. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 11, 2025).

 

 

 

10.22†

 

 

Equity Interest Purchase Agreement, dated December 16, 2024, by and between Talos Production Inc. and Zamajal, S.A. de C.V. (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 17, 2024).

 

 

 

10.23†

 

 

Offer Letter Agreement, dated February 2, 2025, by and between Talos Energy Inc. and Paul Goodfellow, effective February 2, 2025 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025).

 

 

 

10.24†

 

 

Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025).

 

 

 

10.25†

 

 

Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (2024) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024).

 

 

 

10.26†

 

 

Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (2024) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024).

 

 

 

10.27†

 

Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives Retention) (2024) (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 12, 2024).

 

 

 

10.28†

 

Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Stock Price Hurdle) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2025).

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70

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Table of Contents

+

 

+
+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

 

 

 

10.29*

 

 

First Amendment to the Equity Interest Purchase Agreement, dated June 24 2025, by and between Talos Energy LLC, Talos Production Inc., and Zamajal, S.A. de C.V.

 

 

 

10.30*

 

 

Second Amendment to the Equity Interest Purchase Agreement, dated December 11, 2025, by and between Talos Energy LLC, Talos Production Inc., and Zamajal, S.A. de C.V.

 

 

 

19.1

 

Talos Energy Inc. Insider Trading Policy (incorporated by reference to Exhibit 19.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 27, 2025).

 

 

 

21.1*

 

List of Subsidiaries of Talos Energy Inc.

 

 

 

23.1*

 

Consent of Ernst & Young LLP.

 

 

 

23.2*

 

Consent of Netherland, Sewell & Associates, Inc.

 

 

 

24.1*

 

Powers of Attorney (included on signature pages of this Part IV).

 

 

 

31.1*

 

Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

31.2*

 

Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.1**

 

Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

 

 

 

97.1

 

Talos Energy Inc. Executive Compensation Clawback Policy, effective November 15, 2023 (incorporated by reference to Exhibit 97.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

 

 

 

99.1*

 

Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2025.

 

 

 

101.INS*

 

Inline XBRL Instance.

 

 

 

101.SCH*

 

Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents.

 

 

 

104*

 

Cover Page Interactive Data File (Embedded within the Inline XBRL document and included in Exhibit 101).

 

 

 

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

*

 

Filed herewith.

 

 

 

**

 

Furnished herewith.

 

 

 

†

 

Identifies management contracts and compensatory plans or arrangements.

 

 

 

#

 

Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

 

 

 

 

Item 16. Form 10-K Summary

None.

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71

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Table of Contents

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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+ + + +

TALOS ENERGY INC.

Date:

February 24, 2026

By:

/s/ Zachary B. Dailey

Zachary B. Dailey

Executive Vice President and Chief Financial Officer

 

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints William S. Moss, III and Zachary B. Dailey, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + +

Signature

 

Title

 

Date

 

 

 

 

 

/s/ Paul Goodfellow

 

Chief Executive Officer

 

February 24, 2026

Paul Goodfellow

 

(Principal Executive Officer)

 

 

 

 

 

 

 

/s/ Zachary B. Dailey

 

Chief Financial Officer

 

February 24, 2026

Zachary B. Dailey

 

(Principal Financial Officer, Authorized Signatory)

 

 

 

 

 

 

 

/s/ Gregory Babcock

 

Chief Accounting Officer

 

February 24, 2026

Gregory Babcock

 

(Principal Accounting Officer, Authorized Signatory)

 

 

 

 

 

 

 

/s/ Paula R. Glover

 

Director

 

February 24, 2026

Paula R. Glover

 

 

 

 

 

 

 

 

 

/s/ Neal P. Goldman

 

Director

 

February 24, 2026

Neal P. Goldman

 

 

 

 

 

 

 

 

 

/s/ John “Brad” Juneau

 

Director

 

February 24, 2026

John “Brad” Juneau

 

 

 

 

 

 

 

 

 

/s/ Richard Sherrill

 

Director

 

February 24, 2026

Richard Sherrill

 

 

 

 

 

 

 

 

 

/s/ Charles M. Sledge

 

Director

 

February 24, 2026

Charles M. Sledge

 

 

 

 

 

 

 

 

 

/s/ Shandell Szabo

 

Director

 

February 24, 2026

Shandell Szabo

 

 

 

 

 

 

 

 

 

 

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72

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Table of Contents

+

 

+

Index to Consolidated Financial Statements

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ +

Reports of Independent Registered Public Accounting Firm (PCAOB ID 42)

F-2

Consolidated Balance Sheets as of December 31, 2025 and 2024

F-5

Consolidated Statements of Operations for the years ended December 31, 2025, 2024 and 2023

F-6

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2025, 2024 and 2023

F-7

Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023

F-8

Notes to Consolidated Financial Statements

F-9

Note 1 — Organization, Nature of Business and Basis of Presentation

F-9

Note 2 — Summary of Significant Accounting Policies

F-10

Note 3 — Acquisitions and Divestitures

F-15

Note 4 — Property, Plant and Equipment

F-19

Note 5 — Leases

F-20

Note 6 — Financial Instruments

F-21

Note 7 — Equity Method Investments

F-23

Note 8 — Debt

F-24

Note 9 — Asset Retirement Obligations

F-28

Note 10 — Stockholders’ Equity

F-28

Note 11 — Employee Benefit Plans and Share-Based Compensation

F-28

Note 12 — Income Taxes

F-31

Note 13 — Income (Loss) Per Share

F-33

Note 14 — Related Party Transactions

F-34

Note 15 — Commitments and Contingencies

F-34

Note 16 — Segment Information

F-36

Note 17 — Supplemental Oil and Gas Disclosures (Unaudited)

F-39

Note 18 — Subsequent Events

F-42

Schedule to Consolidated Financial Statements

F-43

Schedule I — Condensed Financial Information of Registrant

F-43

 

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F-1

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Table of Contents

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+

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Talos Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 24, 2026 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

+ + + + + + + + + + + + + +
+ + +

 

 

Depreciation, depletion and amortization of oil and natural gas properties and full cost ceiling impairment

Description of the Matter

 

At December 31, 2025, the net book value of the Company’s proved oil and natural gas properties was $3,949 million, and depreciation, depletion and amortization (DD&A) and the full cost ceiling impairment of oil and natural gas properties were $1,054 million and $454 million, respectively for the year then ended. As described in Note 2 to the consolidated financial statements, the Company follows the full cost method of accounting for its oil and gas properties. Depreciation, depletion and amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and natural gas reserves, as estimated by independent petroleum engineers. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved oil and natural gas reserves, discounted at 10%.

Proved oil and gas reserves are prepared using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Judgment is required by the independent and internal petroleum engineers (“engineers”) in estimating proved oil and natural gas reserves. Estimating reserves also requires the selection and evaluation of inputs, including historical production, oil and natural gas price assumptions, operating and capital costs assumptions, among others. Because of the complexity involved in estimating oil and natural gas reserves, management engaged independent petroleum engineers to prepare the proved oil and natural gas reserve estimates for all properties as of December 31, 2025.

+

F-2

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Table of Contents

+

 

+
+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + +

 

 

Auditing the Company’s DD&A expense and full cost ceiling impairment calculations is complex because of the use of the work of engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and natural gas reserves.

How We Addressed the Matter in Our Audit

 

We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense and the full cost ceiling impairment calculations for oil and natural gas properties, including management’s controls over the completeness and accuracy of the financial data and inputs used by the engineers for use in estimating proved oil and natural gas reserves.

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the engineers responsible for the preparation of the reserve estimates. We tested the completeness and accuracy of the financial data and inputs used by the engineers in the estimation of proved oil and natural gas reserves by agreeing significant inputs to source documentation, and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedures on select inputs to the proved oil and natural gas reserve estimate. We also tested the DD&A expense and full cost ceiling impairment calculations for oil and natural gas properties to assess whether they are based on the appropriate proved oil and natural gas reserve volumes as estimated by the engineers.

 

 

 

 

 

Asset retirement obligations

Description of the Matter

 

At December 31, 2025, asset retirement obligations total $1,332 million. As described in Note 2 and 9 of the consolidated financial statements, the Company records a liability for the asset retirement obligation at fair value in the period in which it is incurred. The retirement obligations are periodically adjusted to reflect changes in the expected cash flows resulting from revisions to the estimates of either the timing or amount of the retirement costs. Due to the complexity involved in estimating the expected cash outflows, management used decommissioning engineers to estimate the expected cash outflows for the Company’s asset retirement obligation as of December 31, 2025.

Auditing management’s accounting for retirement obligations was especially challenging as significant judgment is required by the Company in determining the obligations. The significant judgment was primarily related to the inherent estimation uncertainty relating to the expected cash outflows, extent of future asset retirement activities and the timing of asset retirement activities.

How We Addressed the Matter in Our Audit

 

We obtained an understanding, evaluated the design, and tested the operating effectiveness of the controls over the Company’s accounting for asset retirement obligations, including the controls over management’s review of the significant assumptions described above.

To test the asset retirement obligations, among other procedures, we evaluated the methodology, tested the significant assumptions described above and tested the completeness and accuracy of the underlying data used by the Company in estimating the expected cashflows. To assess the estimates of asset retirement activities and cash flows, we evaluated significant changes from the prior estimate, analyzed consistency between the timing of asset retirement activities and projected productive life of the properties, compared cost rates against third-party information or internal cost records and recalculated management’s estimate. We involved our asset retirement specialists to assist in our evaluation of the expected cash outflows for asset retirement obligation.

 

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas

February 24, 2026

+

F-3

+
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Table of Contents

+

 

+

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Talos Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) and our report dated February 24, 2026 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2026

+

F-4

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+

Table of Contents

+

 

+

TALOS ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

ASSETS

 

 

 

 

Current assets:

 

 

 

 

Cash and cash equivalents

$

362,809

 

$

108,172

 

Accounts receivable, net

 

323,058

 

 

404,258

 

Assets from price risk management activities

 

54,420

 

 

33,486

 

Prepaid assets

 

83,080

 

 

77,487

 

Other current assets

 

17,939

 

 

35,980

 

Total current assets

 

841,306

 

 

659,383

 

Property and equipment:

 

 

 

 

Proved properties

 

10,621,012

 

 

9,784,832

 

Unproved properties, not subject to amortization

 

480,555

 

 

587,238

 

Other property and equipment

 

22,643

 

 

35,069

 

Total property and equipment

 

11,124,210

 

 

10,407,139

 

Accumulated depreciation, depletion and amortization

 

(6,686,575

)

 

(5,191,865

)

Total property and equipment, net

 

4,437,635

 

 

5,215,274

 

Other long-term assets:

 

 

 

 

Restricted cash

 

76,181

 

 

106,260

 

Assets from price risk management activities

 

—

 

 

253

 

Equity method investments

 

112,382

 

 

111,269

 

Other well equipment

 

49,307

 

 

58,306

 

Notes receivable, net

 

19,636

 

 

17,748

 

Operating lease assets

 

9,214

 

 

11,294

 

Other assets

 

6,396

 

 

12,008

 

Total assets

$

5,552,057

 

$

6,191,795

 

LIABILITIES AND EQUITY

 

 

 

 

Current liabilities:

 

 

 

 

Accounts payable

$

92,979

 

$

117,055

 

Accrued liabilities

 

290,223

 

 

326,913

 

Accrued royalties

 

59,768

 

 

77,672

 

Current portion of asset retirement obligations

 

112,489

 

 

97,166

 

Liabilities from price risk management activities

 

6,708

 

 

6,474

 

Accrued interest payable

 

48,972

 

 

49,084

 

Current portion of operating lease liabilities

 

3,657

 

 

3,837

 

Other current liabilities

 

29,925

 

 

44,854

 

Total current liabilities

 

644,721

 

 

723,055

 

Long-term liabilities:

 

 

 

 

Long-term debt

 

1,226,189

 

 

1,221,399

 

Asset retirement obligations

 

1,219,639

 

 

1,052,569

 

Liabilities from price risk management activities

 

—

 

 

3,537

 

Operating lease liabilities

 

11,956

 

 

15,489

 

Other long-term liabilities

 

281,429

 

 

416,041

 

Total liabilities

 

3,383,934

 

 

3,432,090

 

Commitments and contingencies (Note 15)

 

 

 

 

Equity:

 

 

 

 

Talos Energy Inc. stockholdersʼ equity:

 

 

 

 

Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2025 and 2024, respectively

 

—

 

 

—

 

Common stock; $0.01 par value; 270,000,000 shares authorized; 188,530,052 and 187,434,908 shares issued as of December 31, 2025 and 2024, respectively

 

1,885

 

 

1,874

 

Additional paid-in capital

 

3,296,643

 

 

3,274,626

 

Accumulated deficit

 

(918,400

)

 

(424,110

)

Treasury stock, at cost; 20,015,369 and 7,417,385 shares as of December 31, 2025 and 2024, respectively

 

(212,144

)

 

(92,685

)

Total Talos Energy Inc. stockholders' equity

 

2,167,984

 

 

2,759,705

 

Noncontrolling interest

 

139

 

 

—

 

Total equity

 

2,168,123

 

 

2,759,705

 

Total liabilities and equity

$

5,552,057

 

$

6,191,795

 

 

+

See accompanying notes.

F-5

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Table of Contents

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TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Revenues:

 

 

 

 

 

 

Oil

 

1,560,401

 

$

1,806,148

 

$

1,357,732

 

Natural gas

 

169,445

 

 

105,528

 

 

68,034

 

NGL

 

50,224

 

 

61,892

 

 

32,120

 

Total revenues

 

1,780,070

 

 

1,973,568

 

 

1,457,886

 

Operating expenses:

 

 

 

 

 

 

Lease operating expense

 

546,716

 

 

566,041

 

 

389,621

 

Production taxes

 

418

 

 

1,377

 

 

2,451

 

Depreciation, depletion and amortization

 

1,056,281

 

 

1,023,558

 

 

663,534

 

Impairment of oil and natural gas properties

 

454,482

 

 

—

 

 

—

 

Accretion expense

 

125,296

 

 

117,604

 

 

86,152

 

General and administrative expense

 

155,368

 

 

201,517

 

 

158,493

 

Other operating (income) expense

 

1,789

 

 

(109,454

)

 

(52,155

)

Total operating expenses

 

2,340,350

 

 

1,800,643

 

 

1,248,096

 

Operating income (expense)

 

(560,280

)

 

172,925

 

 

209,790

 

Interest expense

 

(163,381

)

 

(187,638

)

 

(173,145

)

Price risk management activities income (expense)

 

105,455

 

 

(1,458

)

 

80,928

 

Equity method investment income (expense)

 

(1,807

)

 

(10,289

)

 

(3,209

)

Other income (expense)

 

15,520

 

 

(44,930

)

 

12,371

 

Net income (loss) before income taxes

 

(604,493

)

 

(71,390

)

 

126,735

 

Income tax benefit (expense)

 

109,169

 

 

(5,003

)

 

60,597

 

Net income (loss)

$

(495,324

)

$

(76,393

)

$

187,332

 

Net income (loss) attributable to noncontrolling interest

 

(1,034

)

 

—

 

 

—

 

Net income (loss) attributable to Talos Energy Inc.

$

(494,290

)

$

(76,393

)

$

187,332

 

 

 

 

 

 

 

 

Net income (loss) per share attributable to common stockholders:

 

 

 

 

 

 

Basic

$

(2.82

)

$

(0.44

)

$

1.56

 

Diluted

$

(2.82

)

$

(0.44

)

$

1.55

 

Weighted average common shares outstanding:

 

 

 

 

 

 

Basic

 

175,136

 

 

175,605

 

 

119,894

 

Diluted

 

175,136

 

 

175,605

 

 

120,752

 

 

+

See accompanying notes.

F-6

+
+

Table of Contents

+

 

+

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + + + + +

 

Talos Energy Inc. Stockholders' Equity

 

 

 

 

 

 

Common Stock

 

Additional Paid-In
Capital

 

Accumulated
Deficit

 

Common Stock
Held in Treasury

 

Total
Stockholders' Equity

 

Noncontrolling
Interest

 

Total Equity

 

Balance at December 31, 2022

$

826

 

$

1,699,799

 

$

(535,049

)

$

—

 

$

1,165,576

 

$

—

 

$

1,165,576

 

Equity-based compensation

 

—

 

 

25,008

 

 

—

 

 

—

 

 

25,008

 

 

—

 

 

25,008

 

Equity-based compensation tax withholdings

 

—

 

 

(7,459

)

 

—

 

 

—

 

 

(7,459

)

 

—

 

 

(7,459

)

Equity-based compensation stock issuances

 

11

 

 

(11

)

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

Issuance of common stock for acquisition (Note 3)

 

438

 

 

831,760

 

 

—

 

 

—

 

 

832,198

 

 

—

 

 

832,198

 

Purchase of treasury stock

 

—

 

 

—

 

 

—

 

 

(47,504

)

 

(47,504

)

 

—

 

 

(47,504

)

Net income (loss)

 

—

 

 

—

 

 

187,332

 

 

—

 

 

187,332

 

 

—

 

 

187,332

 

Balance at December 31, 2023

 

1,275

 

 

2,549,097

 

 

(347,717

)

 

(47,504

)

 

2,155,151

 

 

—

 

 

2,155,151

 

Equity-based compensation

 

—

 

 

21,987

 

 

—

 

 

—

 

 

21,987

 

 

—

 

 

21,987

 

Equity-based compensation tax withholdings

 

—

 

 

(6,206

)

 

—

 

 

—

 

 

(6,206

)

 

—

 

 

(6,206

)

Equity-based compensation stock issuances

 

11

 

 

(11

)

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

Issuance of common stock for acquisition (Note 3)

 

243

 

 

322,387

 

 

—

 

 

—

 

 

322,630

 

 

—

 

 

322,630

 

Issuance of common stock (Note 10)

 

345

 

 

387,372

 

 

 

 

 

 

387,717

 

 

—

 

 

387,717

 

Purchase of treasury stock

 

—

 

 

—

 

 

—

 

 

(45,181

)

 

(45,181

)

 

—

 

 

(45,181

)

Net income (loss)

 

—

 

 

—

 

 

(76,393

)

 

—

 

 

(76,393

)

 

—

 

 

(76,393

)

Balance at December 31, 2024

 

1,874

 

 

3,274,626

 

 

(424,110

)

 

(92,685

)

 

2,759,705

 

 

—

 

 

2,759,705

 

Equity-based compensation

 

—

 

 

25,616

 

 

—

 

 

—

 

 

25,616

 

 

—

 

 

25,616

 

Equity-based compensation tax withholdings

 

—

 

 

(3,588

)

 

—

 

 

—

 

 

(3,588

)

 

—

 

 

(3,588

)

Equity-based compensation stock issuances

 

11

 

 

(11

)

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

Issuance of common stock for acquisition (Note 3)

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

Issuance of common stock (Note 10)

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

Initial consolidation of subsidiary

 

—

 

 

—

 

 

—

 

 

—

 

 

—

 

 

1,173

 

 

1,173

 

Purchase of treasury stock

 

—

 

 

—

 

 

—

 

 

(119,459

)

 

(119,459

)

 

—

 

 

(119,459

)

Net income (loss)

 

—

 

 

—

 

 

(494,290

)

 

—

 

 

(494,290

)

 

(1,034

)

 

(495,324

)

Balance at December 31, 2025

$

1,885

 

$

3,296,643

 

$

(918,400

)

$

(212,144

)

$

2,167,984

 

$

139

 

$

2,168,123

 

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

Common Stock Share Activity

Issued

 

Held in Treasury

 

Outstanding

 

Balance at December 31, 2022

 

82,570,328

 

 

—

 

 

82,570,328

 

Equity-based compensation stock issuances

 

1,110,143

 

 

—

 

 

1,110,143

 

Issuance of common stock for acquisitions

 

43,799,890

 

 

—

 

 

43,799,890

 

Purchase of treasury stock

 

—

 

 

(3,400,000

)

 

(3,400,000

)

Balance at December 31, 2023

 

127,480,361

 

 

(3,400,000

)

 

124,080,361

 

Equity-based compensation stock issuances

 

1,105,095

 

 

—

 

 

1,105,095

 

Issuance of common stock for acquisitions

 

24,349,452

 

 

—

 

 

24,349,452

 

Issuance of common stock

 

34,500,000

 

 

—

 

 

34,500,000

 

Purchase of treasury stock

 

—

 

 

(4,017,385

)

 

(4,017,385

)

Balance at December 31, 2024

 

187,434,908

 

 

(7,417,385

)

 

180,017,523

 

Equity-based compensation stock issuances

 

1,095,144

 

 

—

 

 

1,095,144

 

Purchase of treasury stock

 

—

 

 

(12,597,984

)

 

(12,597,984

)

Balance at December 31, 2025

 

188,530,052

 

 

(20,015,369

)

 

168,514,683

 

 

+

See accompanying notes.

F-7

+
+

Table of Contents

+

 

+

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Cash flows from operating activities:

 

 

 

 

 

 

Net income (loss)

$

(495,324

)

$

(76,393

)

$

187,332

 

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion expense

 

1,181,577

 

 

1,141,162

 

 

749,686

 

Impairment of oil and natural gas properties

 

454,482

 

 

—

 

 

—

 

Amortization of deferred financing costs and original issue discount

 

8,359

 

 

9,303

 

 

15,039

 

Equity-based compensation expense

 

18,418

 

 

14,462

 

 

12,953

 

Price risk management activities (income) expense

 

(105,455

)

 

1,458

 

 

(80,928

)

Net cash received (paid) on settled derivative instruments

 

81,471

 

 

4,710

 

 

(9,457

)

Equity method investment (income) expense

 

1,807

 

 

10,289

 

 

3,209

 

Loss (gain) on extinguishment of debt

 

—

 

 

60,256

 

 

—

 

Settlement of asset retirement obligations

 

(117,847

)

 

(108,789

)

 

(86,615

)

Loss (gain) on sale of assets

 

381

 

 

38

 

 

(66,115

)

Loss (gain) on sale of business

 

—

 

 

(100,482

)

 

—

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

85,459

 

 

8,576

 

 

20,352

 

Other current assets

 

15,895

 

 

(6,964

)

 

7,066

 

Accounts payable

 

(22,833

)

 

(3,831

)

 

(60,401

)

Other current liabilities

 

(66,563

)

 

1,290

 

 

(96,960

)

Other non-current assets and liabilities, net

 

(104,001

)

 

7,508

 

 

(76,092

)

Net cash provided by (used in) operating activities

 

935,826

 

 

962,593

 

 

519,069

 

Cash flows from investing activities:

 

 

 

 

 

 

Exploration, development and other capital expenditures

 

(481,905

)

 

(508,914

)

 

(561,434

)

Cash acquired in excess of payments for acquisitions

 

1,690

 

 

—

 

 

17,617

 

Payments for acquisitions, net of cash acquired

 

(49,978

)

 

(936,214

)

 

—

 

Proceeds from (cash paid for) sale of property and equipment, net

 

1,716

 

 

1,161

 

 

73,004

 

Contributions to equity method investees

 

(4,559

)

 

(22,988

)

 

(29,447

)

Investment in intangible assets

 

—

 

 

—

 

 

(12,366

)

Proceeds from sales of business

 

—

 

 

146,676

 

 

—

 

Other

 

(13,710

)

 

—

 

 

—

 

Net cash provided by (used in) investing activities

 

(546,746

)

 

(1,320,279

)

 

(512,626

)

Cash flows from financing activities:

 

 

 

 

 

Issuance of common stock

 

—

 

 

387,717

 

 

—

 

Issuance of senior notes

 

—

 

 

1,250,000

 

 

—

 

Redemption of senior notes

 

—

 

 

(897,116

)

 

(30,000

)

Proceeds from Bank Credit Facility

 

—

 

 

880,000

 

 

825,000

 

Repayment of Bank Credit Facility

 

—

 

 

(1,080,000

)

 

(625,000

)

Deferred financing costs

 

—

 

 

(32,872

)

 

(11,775

)

Other deferred payments

 

(20,539

)

 

(2,389

)

 

(1,545

)

Payments of finance lease

 

(19,589

)

 

(17,834

)

 

(16,306

)

Purchase of treasury stock

 

(119,459

)

 

(45,181

)

 

(47,504

)

Employee stock awards tax withholdings

 

(3,588

)

 

(6,206

)

 

(7,459

)

Distribution to noncontrolling interest

 

(1,347

)

 

—

 

 

—

 

Net cash provided by (used in) financing activities

 

(164,522

)

 

436,119

 

 

85,411

 

 

 

 

 

 

 

 

Net increase (decrease) in cash, cash equivalents and restricted cash

 

224,558

 

 

78,433

 

 

91,854

 

Cash, cash equivalents and restricted cash:

 

 

 

 

 

 

Balance, beginning of period

 

214,432

 

 

135,999

 

 

44,145

 

Balance, end of period

$

438,990

 

$

214,432

 

$

135,999

 

 

 

 

 

 

 

 

Supplemental non-cash transactions:

 

 

 

 

 

 

Capital expenditures included in accounts payable and accrued liabilities

$

84,721

 

$

85,550

 

$

114,972

 

Supplemental cash flow information:

 

 

 

 

 

 

Interest paid, net of amounts capitalized

$

118,037

 

$

130,841

 

$

130,313

 

 

+

See accompanying notes.

F-8

+
+

Table of Contents

+

 

+

TALOS ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2025

Note 1 — Organization, Nature of Business and Basis of Presentation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven, innovative, independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. The Company’s activities are primarily concentrated in the Deepwater (i.e., water depths of more than 600 feet) area of the U.S. Gulf of America. The Company leverages decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest including any variable interest entity in which the Parent Company is the primary beneficiary. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

Segments

From January 1, 2024 through March 18, 2024, the Company had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). Both segments are reportable based on the Company’s measure of segment profit or loss. The legal entities included in the CCS Segment were designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies) and indenture governing the senior notes. See additional information in Note 16 — Segment Information.

Recently Adopted Accounting Standards

Tax Disclosures — In December 2023, the FASB issued an update intended to improve income tax disclosures primarily through expanded disclosure of income tax rate reconciliation items and disaggregation of income taxes paid by jurisdiction. The tabular rate reconciliation requires both percentages and dollars to be presented. This disclosure guidance became effective for annual reporting periods beginning after December 15, 2024. The Company adopted this guidance retrospectively in this Annual Report on Form 10-K for the year ended December 31, 2025, and the adoption of such guidance did not have a material impact on the Company’s consolidated financial statements. See additional information in Note 12 — Income Taxes.

Recently Issued Accounting Standards Not Yet Adopted

Disaggregation of Income Statement Expenses — In November 2024, the FASB issued an update requiring the disaggregated disclosure of income statement expenses. The guidance does not change the expense captions an entity presents on the face of the income statement; rather, it requires disaggregation of certain expense captions into specified categories in disclosures within the footnotes to the financial statements. Such disclosures must be made on an annual and interim basis in a tabular format in the footnotes to the financial statements. Entities will be required to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) depreciation, depletion, and amortization recognized as part of oil- and gas-producing activities or other depletion expenses. The update is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027 on a prospective retrospective basis. Early adoption and retrospective application are permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

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Note 2 — Summary of Significant Accounting Policies

Overview of Significant Accounting Policies

Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents.

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2025 and 2024, the Company had allowances of $17.7 million and $25.5 million, respectively, presented in “Accounts receivable, net” on the Consolidated Balance Sheets.

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the cash flows from derivatives are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Prepaid Assets — Prepaid assets primarily represent prepaid insurance, advance payments to operators, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal and external costs directly related to the acquisition of assets, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, asset retirement costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

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The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Impairment of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures). These escrow accounts were fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets.

Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies, but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20% or more is generally presumed to demonstrate significant influence.

In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statements of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee.

The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2025, 2024 and 2023.

Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants.

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F-11

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Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition, which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities could include optional renewal periods for which it is not contractually obligated, but for which the Company currently expects to exercise such options.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information.

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt when there is a balance outstanding and in “Other assets” on the Consolidated Balance Sheets when no such balance is outstanding.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells and remove or appropriately abandon all production facilities, structures and pipelines following cessation of operations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 15 — Commitments & Contingencies for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees.

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F-12

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The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method.

PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable ranges from zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs and PSUs. See Note 13 — Income (Loss) Per Share for additional information.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

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Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•
Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•
Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.
•
Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•
Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
•
Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).
•
Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information.

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets the majority of its oil and natural gas production, and all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and gas pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary.

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F-14

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The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Shell Trading (US) Company

 

35

%

 

48

%

 

54

%

Exxon Mobil Corporation

 

23

%

 

17

%

**

 

Valero Energy Corporation

**

 

**

 

 

21

%

Chevron Corporation

 

12

%

**

 

**

 

 

** Less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Cash and cash equivalents

$

362,809

 

$

108,172

 

Restricted cash included in Other long-term assets

 

76,181

 

 

106,260

 

Total cash, cash equivalent and restricted cash

$

438,990

 

$

214,432

 

The decrease in restricted cash is a result of amounts being released from the escrow account upon the completion of certain P&A work.

Accounts Receivable

The following table provides the components of “Accounts receivable, net” as presented on the Consolidated Balance Sheets (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Trade

$

166,793

 

$

236,694

 

Joint interest

 

132,527

 

 

133,562

 

Other

 

23,738

 

 

34,002

 

Total accounts receivable, net

$

323,058

 

$

404,258

 

 

Note 3 — Acquisitions and Divestitures

Acquisitions — Business Combinations

Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date.

QuarterNorth Acquisition — On March 4, 2024, the Company completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately-held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition,” and the merger agreement related thereto, the “QuarterNorth Merger Agreement”) for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with a January 2024 underwritten public offering of 34.5 million shares of the Company’s common stock (See Note 10 — Stockholders’ Equity), borrowings under the Bank Credit Facility and the Senior Notes (as defined in Note 8 — Debt).

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F-15

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The following table summarizes the purchase price (in thousands, except share and per share data):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

Shares of Talos common stock

 

24,349,452

 

Talos common stock price(1)

$

13.25

 

Common stock value

$

322,630

 

 

 

 

Cash consideration

$

1,247,419

 

 

 

 

Total purchase price(2)

$

1,570,049

 

(1)
Represents the closing price of the Company’s common stock on March 4, 2024, the date of the closing of the QuarterNorth Acquisition.
(2)
Total purchase price net of $331.4 million cash and cash equivalents acquired at closing is $1,238.7 million.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on March 4, 2024 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

Cash and cash equivalents

$

331,374

 

Other current assets(1)

 

165,696

 

Property and equipment

 

1,622,414

 

Other long-term assets

 

20,781

 

Current liabilities:

 

 

Current portion of asset retirement obligations

 

(6,748

)

Other current liabilities

 

(199,704

)

Long-term liabilities:

 

 

Asset retirement obligations

 

(192,771

)

Deferred tax liabilities

 

(168,102

)

Other long-term liabilities

 

(2,891

)

Allocated purchase price

$

1,570,049

 

(1)
Included in current assets is acquired receivables in the amount of $136.3 million excluding receivables with credit deterioration, which represents the contractual value net of allowances of approximately $15.5 million.

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were generally equivalent to the carrying value due to their short-term nature.

The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating, development and plugging and abandonment costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped and probable reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on NYMEX forward strip prices, escalated for inflation, and adjusted for price differentials.

The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.

The fair values of derivative instruments were estimated using a third-party industry standard pricing model which considers various inputs such as quoted forward commodity prices, discount rates, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant data.

The Company incurred approximately $21.6 million of acquisition-related costs in connection with the QuarterNorth Acquisition exclusive of severance expense, of which $18.6 million was recognized during the year ended December 31, 2024 and $3.0 million was recognized for the year ended December 31, 2023. These costs were reflected in “General and administrative expense” on the Consolidated Statements of Operations except for $4.9 million of fees associated with an unutilized bridge loan that was included in “Interest expense” on the Consolidated Statements of Operations during the year ended December 31, 2024. Additionally, the Company incurred $22.2 million in severance expense in connection with the QuarterNorth Acquisition for the year ended December 31, 2024. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional discussion.

+

F-16

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Table of Contents

+

 

+

The following table presents revenue and net income attributable to the QuarterNorth Acquisition for the period from March 4, 2024 to December 31, 2024:

+ + + + + + + + + + + + + + + +
+ + + +

Revenue

$

503,397

 

Net income (loss)

$

89,209

 

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2024 and 2023 as if the QuarterNorth Acquisition had occurred on January 1, 2023. The unaudited pro forma information was derived from historical statements of operations of the Company and QuarterNorth adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and Senior Notes, (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) weighted average basic and diluted shares of common stock outstanding from the issuance of 24.3 million shares of common stock as partial consideration for the QuarterNorth Acquisition and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 34.5 million shares of common stock from the underwritten public offering in January 2024 that partially funded the cash portion of the QuarterNorth Acquisition. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to include $31.7 million of general and administrative expenses and supplemental pro forma earnings for the year ended December 31, 2024 were adjusted to exclude these expenses. This information does not purport to be indicative of results of operations that would have occurred had the QuarterNorth Acquisition occurred on January 1, 2023, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2024

 

2023

 

Revenue

$

2,100,837

 

$

2,141,579

 

Net income (loss)

$

(69,131

)

$

245,720

 

Basic net income (loss) per common share

$

(0.38

)

$

1.37

 

Diluted net income (loss) per common share

$

(0.38

)

$

1.37

 

EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivable balance of $8.4 million. No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility.

The following table summarizes the purchase price (in thousands, except share and per share data):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

Talos common stock

 

43,799,890

 

Talos common stock price per share(1)

$

19.00

 

Common stock value

$

832,198

 

 

 

 

Cash consideration

$

207,313

 

Settlement of preexisting relationship

$

8,388

 

 

 

 

Total purchase price

$

1,047,899

 

 

(1)
Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.8 million was recognized during the year ended December 31, 2023 and reflected in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $25.3 million in severance expense in connection with the EnVen Acquisition for the year ended December 31, 2023. See Note 11 — Employee Benefit Plans and Share-Based Compensation for additional discussion.

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands):

+ + + + + + + + + + + + + + + +
+ + + +

Revenue

$

423,624

 

Net income (loss)

$

85,622

 

 

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F-17

+
+

Table of Contents

+

 

+

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the year ended December 31, 2023 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

 

Year Ended December 31,

 

 

2023

 

Revenue

$

1,509,929

 

Net income (loss)

$

217,537

 

Basic net income (loss) per common share

$

1.74

 

Diluted net income (loss) per common share

$

1.73

 

 

Asset Acquisitions

Acquisitions accounted for as asset acquisitions require, among other items, the cost of the acquisition to be allocated to the assets acquired and liabilities assumed based on relative fair value basis.

Acquisition of Working Interests in Monument Oil Discovery — The Company executed two separate definitive agreements to acquire a collective 21.4% non-operated working interest in the Monument oil discovery (“Monument Project”) in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks. Cash consideration totaling $20.2 million, after customary closing adjustments, was paid on the closing dates of July 31, 2024 and August 2, 2024 with $24.4 million of additional cash consideration paid periodically in installments beginning January 1, 2025 through April 1, 2026. The Company allocated $42.6 million to proved properties. The carrying amount for the deferred cash consideration of $4.0 million is included in “Other current liabilities” on the Consolidated Balance Sheets at December 31, 2025.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an additional 8.3% non-operated working interest in the Monument Project for $14.8 million, substantially all of which was allocated to its proved properties. An additional aggregate $6.3 million of contingent payments will be recognized upon the achievement of certain milestones defined in the agreement.

Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50.0% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively (the “Amberjack Acquisition”), in the Deepwater area. Prior to the Amberjack Acquisition, the Company owned an interest in and operated these developed and producing blocks. The Company also acquired a controlling financial interest in SP 49 Pipeline LLC (“SP 49”) as part of the Amberjack Acquisition. The one-third equity interest in SP 49 not held by the Company is presented as “Noncontrolling interest” in the Company’s Consolidated Financial Statements. The $38.6 million cost of the Amberjack Acquisition, including $33.7 million of cash at closing, was primarily allocated to the Company’s proved properties.

Divestitures

Talos Low Carbon Solutions Divestiture — On March 18, 2024, the Company entered into a definitive agreement relating to and subsequently completed the sale of its wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture included the Company’s entire CCS business including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC, Harvest Bend CCS LLC, and Coastal Bend CCS LLC. The TLCS Divestiture also entitled Talos to certain contingent payments, of which $4.7 million was received during the year ended December 31, 2024. A gain of $100.4 million was recognized related to TLCS Divestiture during the year ended December 31, 2024. The gain on the TLCS Divestiture is presented as “Other operating income (expense)” on the Consolidated Statements of Operations and the contingent payments are included in “Other current assets” on the Consolidated Balance Sheets at December 31, 2025. A deferred payment of $12.5 million due in October 2025 has not been received and the Company determined there was significant doubt surrounding the collectability of such deferred payment. Accordingly, the Company derecognized the deferred payment, of which $8.9 million is reflected as an expense in “Other operating income (expense)” and $3.6 million is reflected as the reversal of imputed interest income in “Other income (expense)” on the Consolidated Statements of Operations for the year ended December 31, 2025.

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+

 

+

The Company incurred approximately $6.1 million of costs in connection with the TLCS Divestiture exclusive of severance expense, of which $5.5 million was recognized during the year ended December 31, 2024 and reflected in “General and administrative expense” on the Consolidated Statements of Operations. Additionally, the Company incurred $3.7 million in severance expense in connection with the TLCS Divestiture for the year ended December 31, 2024. See Note 11 — Employee Benefits Plans and Share-Based Compensation for additional discussion.

Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V. (“Zamajal”), a subsidiary of Grupo Carso, S.A.B. de C.V. (“Carso”) for $74.9 million in cash consideration with an additional $49.9 million contingent on first oil production from the Zama Field (the “2023 Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, currently holds a 17.4% unitized interest in the Zama Field.

The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million upon the closing of the 2023 Mexico Divestiture. Fair value was determined using the implied value of Talos Mexico, based on the transaction price from the 2023 Mexico Divestiture, an orderly market transaction. A gain of $66.2 million was recognized on the 2023 Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations.

On December 16, 2024, the Company entered into an agreement to sell an additional equity interest in Talos Mexico to Zamajal. See Note 7 — Equity Method Investments for additional information.

Note 4 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of America deep and shallow waters. The Company’s ceiling test computations resulted in an impairment of its U.S. oil and natural gas properties during the year ended December 31, 2025 of $454.5 million. No impairment charges were recorded during the years ended December 31, 2024 and 2023. At December 31, 2025, its ceiling test computation was based on SEC pricing of $65.37 per Bbl of oil, $3.61 per Mcf of natural gas and $19.22 per Bbl of NGLs.

Further ceiling test impairments could be recorded in the near term should the 12-month average trailing commodity prices decline as compared to the commodity prices used in prior quarters.

Unproved Properties

Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of America federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest.

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2025, by the year in which such costs were incurred (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + +

 

 

 

Year Ended December 31,

 

 

Total

 

2025

 

2024

 

2023

 

2022 and Prior

 

Acquisition United States

$

400,677

 

$

—

 

$

263,783

 

$

136,894

 

$

—

 

Exploration United States

 

79,878

 

 

41,576

 

 

26,314

 

 

9,585

 

 

2,403

 

Total unproved properties, not subject to amortization

$

480,555

 

$

41,576

 

$

290,097

 

$

146,479

 

$

2,403

 

 

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates the majority of these costs to be transferred to the amortization base within six years of December 31, 2025.

+

F-19

+
+

Table of Contents

+

 

+

Note 5 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly.

The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Finance lease costs - interest on lease liabilities

$

11,193

 

$

12,948

 

$

14,476

 

Operating lease costs, excluding short-term leases(1)

 

4,192

 

 

4,207

 

 

4,883

 

Short-term lease costs(2)

 

151,379

 

 

100,895

 

 

117,132

 

Variable lease costs(3)

 

2,668

 

 

2,464

 

 

2,888

 

Variable and fixed sublease income

 

(1,586

)

 

(1,436

)

 

(482

)

Total lease costs

$

167,846

 

$

119,078

 

$

138,897

 

 

(1)
Operating lease costs reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.
(2)
Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs and well intervention vessels, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets. The short-term operating lease costs incurred during the periods presented are not necessarily indicative of the Company’s future short-term lease costs and obligations, as it routinely executes short-term contracts for the use of drilling rigs to support its drilling activities. Short-term lease costs for drilling rigs can vary significantly based on the timing of the drilling program. Market conditions can also contribute to the volatility and variability of short-term drilling rig lease costs.
(3)
Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

December 31, 2025

 

December 31, 2024

 

Operating leases:

 

 

 

 

Operating lease assets

$

9,214

 

$

11,294

 

 

 

 

 

 

Current portion of operating lease liabilities

$

3,657

 

$

3,837

 

Operating lease liabilities

 

11,956

 

 

15,489

 

Total operating lease liabilities

$

15,613

 

$

19,326

 

 

 

 

 

 

Finance leases:

 

 

 

 

Proved properties

$

166,261

 

$

166,261

 

 

 

 

 

 

Other current liabilities

$

21,473

 

$

19,589

 

Other long-term liabilities

 

90,169

 

 

111,641

 

Total finance lease liabilities

$

111,642

 

$

131,230

 

 

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F-20

+
+

Table of Contents

+

 

+

The table below presents the lease maturity by year as of December 31, 2025 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets.

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Operating Leases

 

Finance Leases

 

2026

$

5,072

 

$

30,782

 

2027

 

4,753

 

 

30,782

 

2028

 

4,610

 

 

30,782

 

2029

 

3,226

 

 

30,782

 

2030

 

1,223

 

 

12,826

 

Thereafter

 

135

 

 

—

 

Total lease payments

$

19,019

 

$

135,954

 

Imputed interest

 

(3,406

)

 

(24,312

)

Total lease liabilities

$

15,613

 

$

111,642

 

 

The table below presents the weighted average remaining lease term and discount rate related to leases:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Weighted average remaining lease term:

 

 

 

 

 

 

Operating leases

3.9 years

 

4.8 years

 

5.9 years

 

Finance leases

4.4 years

 

5.4 years

 

6.4 years

 

Weighted average discount rate:

 

 

 

 

 

 

Operating leases

 

10.8

%

 

10.7

%

 

10.8

%

Finance leases

 

9.2

%

 

9.2

%

 

9.2

%

 

The table below presents the supplemental cash flow information related to leases (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Operating cash outflow from finance leases

$

11,193

 

$

12,948

 

$

14,476

 

Operating cash outflow from operating leases

$

5,830

 

$

5,634

 

$

6,318

 

 

 

 

 

 

 

 

ROU assets obtained in exchange for new operating lease liabilities(1)

$

—

 

$

1,909

 

$

12,971

 

Remeasurement of lease liability arising from modification of ROU asset(2)

$

—

 

$

—

 

$

(5,124

)

 

(1)
See QuarterNorth Acquisition and EnVen Acquisition each in Note 3 — Acquisitions and Divestitures.
(2)
Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

Note 6 — Financial Instruments

As of December 31, 2025 and 2024, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

Debt Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

December 31, 2025

 

December 31, 2024

 

 

Carrying
Amount

 

Fair
Value

 

Carrying
Amount

 

Fair
Value

 

9.000% Second-Priority Senior Secured Notes

$

614,058

 

$

649,425

 

$

611,135

 

$

640,619

 

9.375% Second-Priority Senior Secured Notes

$

612,131

 

$

656,250

 

$

610,264

 

$

635,750

 

 

The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets. See Note 8 — Debt for the maturity dates of the Company’s Senior Notes.

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F-21

+
+

Table of Contents

+

 

+

The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Net cash received (paid) on settled derivative instruments

$

81,471

 

$

4,710

 

$

(9,457

)

Unrealized gain (loss)

 

23,984

 

 

(6,168

)

 

90,385

 

Price risk management activities income (expense)

$

105,455

 

$

(1,458

)

$

80,928

 

 

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2025:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + +

Swap Contracts

 

Production Period

Settlement Index

Volumes

 

Swap Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

January 2026 – December 2026

NYMEX WTI CMA

 

8,197

 

$

65.51

 

Natural gas:

 

(MMBtu)

 

(per MMBtu)

 

January 2026 – December 2026

NYMEX Henry Hub

 

28,671

 

$

3.85

 

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + +

Two-Way Collar Contracts

 

Production Period

Settlement Index

Volumes

 

Floor Price

 

Ceiling Price

 

Crude oil:

 

(Bbls)

 

(per Bbl)

 

(per Bbl)

 

January 2026 – December 2026

NYMEX WTI CMA

 

11,997

 

$

60.00

 

$

68.25

 

 

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

December 31, 2025

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

$

—

 

$

54,420

 

$

—

 

$

54,420

 

Liabilities:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

 

—

 

 

(6,708

)

 

—

 

 

(6,708

)

Total net asset (liability)

$

—

 

$

47,712

 

$

—

 

$

47,712

 

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

December 31, 2024

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

$

—

 

$

33,739

 

$

—

 

$

33,739

 

Liabilities:

 

 

 

 

 

 

 

 

Oil and natural gas derivatives

 

—

 

 

(10,011

)

 

—

 

 

(10,011

)

Total net asset (liability)

$

—

 

$

23,728

 

$

—

 

$

23,728

 

 

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+
+

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+

 

+

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

December 31, 2025

 

December 31, 2024

 

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

Oil and natural gas derivatives:

 

 

 

 

 

 

 

 

Current

$

54,420

 

$

6,708

 

$

33,486

 

$

6,474

 

Non-current

 

—

 

 

—

 

 

253

 

 

3,537

 

Total gross amounts presented on balance sheet

 

54,420

 

 

6,708

 

 

33,739

 

 

10,011

 

Less: Gross amounts not offset on the balance sheet

 

6,708

 

 

6,708

 

 

10,011

 

 

10,011

 

Net amounts

$

47,712

 

$

—

 

$

23,728

 

$

—

 

 

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2025 represent derivative instruments from eight counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating and are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2025 would have been $47.7 million.

Note 7 — Equity Method Investments

Talos Mexico

See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. On December 16, 2024, the Company entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal, a subsidiary of Carso, for $49.7 million in cash consideration with an additional $33.1 million contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale is expected to close no later than May of 2026 upon the satisfaction of customary closing conditions and the receipt of all regulatory approvals. As of December 31, 2025, Talos Mexico, which currently holds a 17.4% interest in the Zama Field, is owned 50.1% by the Company and 49.9% by Zamajal. See Note 14 — Related Party Transactions for additional information on Carso.

The carrying amount of the Company’s investment in Talos Mexico was $112.4 million and $111.3 million as of December 31, 2025 and 2024, respectively. The carrying amount of the investment includes a $66.0 million positive basis difference, which will be amortized using the units-of-production method upon commencement of regular commercial production from the Zama Field.

Bayou Bend CCS LLC

In March 2024, the Company sold its entire CCS business inclusive of Bayou Bend CCS LLC (“Bayou Bend”). See Note 3 – Acquisitions and Divestitures for additional information on the TLCS Divestiture. During the year ended December 31, 2023, Chevron U.S.A. Inc. (“Chevron”) made $8.6 million of contributions to Bayou Bend on the Company’s behalf in accordance with an agreement executed in 2022. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million gain during the year ended December 31, 2023 on the funding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations.

VIE Disclosures

VIE and Primary Beneficiary Determination — Talos Mexico was determined to be a VIE. Talos Mexico did not have sufficient equity at risk to finance activities without additional subordinated financial support. The Company is not the primary beneficiary of Talos Mexico due to the governance structure of this entity. The most significant activities of Talos Mexico are jointly controlled by the owners.

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F-23

+
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Table of Contents

+

 

+

Financings — Talos Mexico has historically been funded through equity contributions from owners.

Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with Talos Mexico is the carrying amount of its investment.

Nature of Risks — Talos Mexico holds a working interest in the unitized Zama Field. Developing oil fields with partners involves certain operational risks - namely, disagreements over project management, reliance on the operator’s capabilities, and high capital expenditures. An Integrated Project Team (“IPT”) reporting to the Zama Unit Operating Committee, was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. Even though an IPT exists, teamwork could remain a challenge. The Zama Unit Development Plan (“UDP”) was approved by CNH in June 2023. Final Investment Decision (“FID”) is expected following completion and final review of the front-end engineering and design (“FEED”), project financing and final approvals. Achieving FID is a crucial stage and marks the beginning of the engineering and construction stage. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the project. On December 31, 2025, operatorship of the Zama Unit was transferred from Petróleos Mexicanos to Harbour Energy.

Note 8 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + +

 

Maturity Date

December 31, 2025

 

December 31, 2024

 

9.000% Second-Priority Senior Secured Notes

February 1, 2029

$

625,000

 

$

625,000

 

9.375% Second-Priority Senior Secured Notes

February 1, 2031

 

625,000

 

 

625,000

 

Bank Credit Facility

March 31, 2027

 

—

 

 

—

 

Total debt, before discount and deferred financing cost

 

 

1,250,000

 

 

1,250,000

 

Unamortized discount and deferred financing cost, net

 

 

(23,811

)

 

(28,601

)

Total debt

 

$

1,226,189

 

$

1,221,399

 

9.000% Second-Priority Senior Secured Notes—due February 2029

The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024.

At any time prior to February 1, 2026, the Company may redeem up to 40% of the principal amount of the 9.000% Notes at a redemption rate of 109.00% of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2026, the Company may also redeem some or all of the 9.000% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.000% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + +

Period

 

Redemption Price

 

2026

 

 

104.500

%

2027

 

 

102.250

%

2028 and thereafter

 

 

100.000

%

As of December 31, 2024, the Company has incurred debt issuance costs of $16.3 million related to the 9.000% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued. See Note 3 — Acquisitions and Divestitures for further discussion on the QuarterNorth Acquisition.

+

F-24

+
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Table of Contents

+

 

+

9.375% Second-Priority Senior Secured Notes—due February 2031

The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024.

At any time prior to February 1, 2027, the Company may redeem up to 40% of the principal amount of the 9.375% Notes at a redemption rate of 109.375% of the principal amount plus accrued and unpaid interest. At any time prior to February 1, 2027, the Company may also redeem some or all of the 9.375% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, the Company may redeem all or a portion of the 9.375% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 1 of the years set forth below:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + +

Period

 

Redemption Price

 

2027

 

 

104.688

%

2028

 

 

102.344

%

2029 and thereafter

 

 

100.000

%

As of December 31, 2024, the Company has incurred debt issuance costs of $16.3 million related to the 9.375% Notes issued as part of the debt offering that partially funded the cash portion of the QuarterNorth Acquisition. The debt issue costs reduced the proceeds from the debt issued.

Debt Covenants for 9.000% Notes and 9.375% Notes

Each of the indentures that govern the 9.000% Notes and the 9.375% Notes contain covenants that, among other things, limit the Issuer’s ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions or dividends on equity interests, redeem or repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from the Issuer’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of the Issuer’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. These covenants are subject to certain exceptions and qualifications. The Company was in compliance with all debt covenants at December 31, 2025.

12.00% Second-Priority Senior Secured Notes

On February 7, 2024, the Company redeemed $638.5 million aggregate principal amount of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) at 103.000% plus accrued and unpaid interest using the proceeds from the issuance of the Senior Notes. The debt redemption resulted in a loss on extinguishment of debt of $54.9 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations.

11.75% Senior Secured Second Lien Notes

On February 7, 2024, the Company redeemed $227.5 million aggregate principal amount of the 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) at 102.938% plus accrued and unpaid interest using the proceeds from the issuance of the Senior Notes. The debt redemption resulted in a loss on extinguishment of debt of $5.4 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations.

Bank Credit Facility

The Company maintains the Bank Credit Facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that the Company delivers to the administrative agent of its Bank Credit Facility.

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F-25

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Table of Contents

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+

On August 4, 2025, the Company entered into the Borrowing Base Redetermination Agreement and Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, among other things, (i) decreased both the borrowing base and commitments to $700.0 million and (ii) removed the $50.0 million cap on the amount of unrestricted cash that may be deducted in the calculation of consolidated total debt (used to calculate the Consolidated Total Debt to EDITDAX ratio under the Bank Credit Facility) if, as of the applicable date of determination, each lender’s total exposure is $0.

Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + +

Borrowing Base Utilization Percentage

 

Utilization

 

Term Benchmark Loans and RFR Loans

 

ABR Loans

 

Commitment
Fee Rate

Level 1

 

< 25%

 

2.75%

 

1.75%

 

0.38%

Level 2

 

≥ 25% < 50%

 

3.00%

 

2.00%

 

0.38%

Level 3

 

≥ 50% < 75%

 

3.25%

 

2.25%

 

0.50%

Level 4

 

≥ 75% < 90%

 

3.50%

 

2.50%

 

0.50%

Level 5

 

≥ 90%

 

3.75%

 

2.75%

 

0.50%

 

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0% of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

As of December 31, 2025, the Company's borrowing base was $700.0 million with total commitments of $700.0 million. Additionally, no more than $250.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $250.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2025. See Note 15 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2025.

Subsequent Event — On January 20, 2026, Talos Energy Inc., Talos Production Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Talos Production”), and certain other direct and indirect subsidiaries of the Company and Talos Production entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), the issuing banks, the lenders party thereto, and the other persons from time to time party thereto. The A&R Credit Agreement amends and restates in its entirety the credit agreement, dated as of May 10, 2018 (as amended from time to time, the “Existing Credit Agreement”), by and among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the issuing banks, the lenders party thereto, and the other persons party thereto.

This credit facility has an initial borrowing base and total commitments of $700.0 million (with a letter of credit facility with a $250 million sublimit), subject to redetermination by the lenders at least semi-annually during the second quarter and fourth quarter of each year. The maturity date of the A&R Credit Agreement is the earlier of (i) January 20, 2030 and (ii) November 2, 2028 (the 91st day prior to the earliest stated maturity date of the 9.000% Notes, (or any Permitted Refinancing Indebtedness with respect thereto)), if such notes (or such Permitted Refinancing Indebtedness) have not been refinanced, redeemed, or repaid in full on prior to such 91st day.

Interest accrues at Talos Production’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months and six-months) calculated and published by the CME Group Inc. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York. In addition, Talos Production is obligated to pay a commitment fee on the unutilized portion of the commitments. The applicable margin and the commitment fee rate are calculated based upon the utilization levels as a percentage of unused lender commitments then in effect.

+

F-26

+
+

Table of Contents

+

 

+

The A&R Credit Agreement includes certain conditions to borrowings, representations and warranties and events of default customary for financings of its type and size. The A&R Credit Agreement also limits the Company’s, Talos Production’s and their respective subsidiaries’ ability to, among other things, incur additional indebtedness, grant liens on any assets, pay dividends or make certain restricted payments, make certain investments, consummate certain asset sales, make certain payments on indebtedness, and merge, consolidate or engage in other fundamental changes. The A&R Credit Agreement has certain customary affirmative and negative covenants, including that Talos Production must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of no greater than to 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. Talos Production must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the A&R Credit Agreement, unutilized commitments are included in current assets in the current ratio calculation. This credit facility is secured by, among other things, mortgages covering at least 85.0% of the proved oil and natural gas assets of the Company and is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

Limitation on Restricted Payments Including Dividends

The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s equity method investee as of December 31, 2025 did not have any undistributed earnings.

The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.

In addition, each of the indentures governing the Senior Notes restrict the Issuer and its restricted subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indentures. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the Issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of at least 2.25 to 1.00, (iii) immediately after giving effect to such transaction on a pro forma basis, the consolidated leverage ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture.

At December 31, 2025, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.

+

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Table of Contents

+

 

+

Note 9 — Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Balance, beginning of period

$

1,149,735

 

$

897,226

 

Obligations assumed(1)

 

10,868

 

 

199,519

 

Obligations incurred

 

14,146

 

 

107

 

Obligations settled

 

(117,847

)

 

(108,789

)

Obligations divested

 

(3,150

)

 

—

 

Accretion expense

 

125,296

 

 

117,604

 

Changes in estimate(2)

 

153,080

 

 

44,068

 

Balance, end of period

$

1,332,128

 

$

1,149,735

 

Less: Current portion

 

112,489

 

 

97,166

 

Long-term portion

$

1,219,639

 

$

1,052,569

 

 

(1)
Obligations assumed during the year ended December 31, 2024 were in connection with the QuarterNorth Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.
(2)
Changes in estimate were primarily due to changes in expected timing and cost estimates to satisfy certain future abandonment obligations.

At December 31, 2025, the Company has (1) restricted cash of $76.2 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable with an aggregate face value of $66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Significant Accounting Policies.

Note 10 — Stockholders’ Equity

Underwritten Equity Offering

On January 22, 2024, we closed an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. See Note 3 – Acquisitions and Divestitures for additional information on the QuarterNorth Acquisition.

Note 11 — Employee Benefits Plans and Share-Based Compensation

Severance

During the years ended December 31, 2024 and 2023, the Company accrued severance costs of $26.0 million and $25.3 million, respectively, in connection with the EnVen Acquisition, QuarterNorth Acquisition and TLCS Divestiture. See Note 3 — Acquisitions and Divestitures for additional information. The involuntary termination benefits were provided pursuant to (i) a one-time benefit arrangement that was recognized over the future service period through the termination date and (ii) contractual termination benefits required by the terms of existing employment agreements. Severance costs are reflected in “General and administrative expense” on the Consolidated Statements of Operations. The severance accrual had been reduced to an immaterial amount by December 31, 2024.

In connection with the departure of the Company’s former President and Chief Executive Officer on August 29, 2024, the Company incurred $5.0 million of severance, all of which is reflected in “General and administrative expense” on the Consolidated Statements of Operations.

Long Term Incentive Plan

The Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (the “A&R LTIP”) became effective on May 23, 2024 and authorizes the Company to grant awards of up to 12,439,415 shares of the Company’s common stock, subject to the share recycling and adjustment provisions of the A&R LTIP. The A&R LTIP also extends the term of the plan to May 23, 2034.

The A&R LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the A&R LTIP.

Award of Vested Stock — On November 1, 2024, the Company entered into a separation and release agreement with its former President and Chief Executive Officer and granted, pursuant to the A&R LTIP, a stock award of 28,519 fully vested shares of the Company’s common stock. This grant represented the pro rata portion of the Company’s 2024 LTIP award to which the former executive was entitled.

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Restricted Stock Units – Employees — RSUs granted to employees under the A&R LTIP primarily vest ratably over an approximate three-year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2025 was approximately $31.5 million, which is expected to be recognized over a weighted average period of 1.8 years.

On September 9, 2024, there were 157,071 RSUs issued as retention awards to executive officers that were required to report their beneficial ownership of the Company's equity securities and any transactions in such securities. These retention RSUs will vest ratably on each of September 9, 2025, September 9, 2026, and September 9, 2027.

On November 1, 2024, the Company’s former Interim Chief Executive Officer and President was granted 43,630 RSUs, all of which vested on December 31, 2024. The Company’s former Interim Chief Executive Officer and President also agreed to forfeit 4,273 RSUs that he was granted in 2024 for his service as a non-employee member of the Board.

Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the A&R LTIP vest approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Each non-employee director is provided the opportunity to defer the settlement of their RSUs until a later date, as timely selected pursuant to a deferral election form. Following the vesting date, or such later date as elected by the director pursuant to the deferral election, these RSUs are settled 60% in shares of our common stock and 40% in cash, unless the director timely elects for the awards to be settled 100% in shares of our common stock.

The following table summarizes RSU activity:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Restricted
Stock Units

 

Weighted Average
Grant Date Fair Value

 

Unvested RSUs at December 31, 2022

 

3,215,504

 

$

12.79

 

Granted

 

1,154,541

 

$

16.24

 

Vested

 

(1,730,959

)

$

11.97

 

Forfeited

 

(332,725

)

$

14.52

 

Unvested RSUs at December 31, 2023

 

2,306,361

 

$

14.89

 

Granted

 

3,155,776

 

$

11.97

 

Vested

 

(1,534,798

)

$

13.72

 

Forfeited

 

(384,904

)

$

14.65

 

Unvested RSUs at December 31, 2024

 

3,542,435

 

$

12.83

 

Granted

 

3,017,967

 

$

8.80

 

Vested

 

(1,484,838

)

$

13.46

 

Forfeited

 

(479,809

)

$

10.25

 

Unvested RSUs at December 31, 2025

 

4,595,755

 

$

10.25

 

Performance Share Units – Employees — PSUs granted to employees under the A&R LTIP represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable ranges from zero to 200% of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2025 was approximately $6.9 million, which is expected to be recognized over a weighted average period of 1.8 years.

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The following table summarizes PSU activity:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Performance
Share Units

 

Weighted Average
Grant Date Fair Value

 

Unvested PSUs at December 31, 2022

 

638,601

 

$

23.66

 

Granted(1)

 

595,394

 

$

18.76

 

Forfeited

 

(217,346

)

$

21.28

 

Unvested PSUs at December 31, 2023

 

1,016,649

 

$

21.30

 

Granted(2)

 

299,472

 

$

11.36

 

Forfeited(3)

 

(666,455

)

$

22.71

 

Unvested PSUs at December 31, 2024

 

649,666

 

$

15.27

 

Granted(4)

 

1,014,647

 

$

9.87

 

Forfeited(5)

 

(550,014

)

$

15.94

 

Unvested PSUs at December 31, 2025

 

1,114,299

 

$

10.02

 

 

(1)
There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.
(2)
Eligible to vest based on continued employment and the relative annualized TSR of the Company as compared to a peer group over a three-year performance period, as modified by the Company’s absolute annualized TSR over the same performance period. Additionally, on November 1, 2024, the Company entered into a separation and release agreement with its former President and Chief Executive Officer and granted, pursuant to the A&R LTIP, an award of 38,844 PSUs. This grant represented the pro rata portion of the Company’s 2024 LTIP award to which the former executive was entitled.
(3)
The performance period for 475,604 PSUs ended on December 31, 2024. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2025. Since these awards were legally forfeited they were added back to the plan reserve for future grants under the recycling provisions of the A&R LTIP.
(4)
There were 837,066 PSUs granted that are eligible to vest based on continued employment and the relative annualized TSR of the Company as compared to a peer group over a three-year performance period, as modified by the Company’s absolute annualized TSR over the same performance period. The remaining PSUs granted are eligible to vest based on continued employment and the achievement of certain stock-price hurdles over a three-year performance period.
(5)
The performance period for 317,494 PSUs ended on December 31, 2025. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2026. Since these awards were legally forfeited, they were added back to the plan reserve for future grants under the recycling provisions of the A&R LTIP.

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted during the periods indicated:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

 

Year Ended December 31,

 

2025

2024

2023

Expected term (in years)

2.3 - 2.8

2.2 - 2.3

2.1 - 2.8

Expected volatility

45.6 - 52.4%

49.5 - 54.4%

61.9 - 73.1%

Risk-free interest rate

3.5 - 3.8%

3.6 - 4.1%

4.4 - 4.6%

Dividend yield

— %

— %

— %

 

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by (used in) operating activities” on the Consolidated Statements of Cash Flows.

The following table presents the amount of costs expensed and capitalized (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Share-based compensation costs

$

25,967

 

$

22,088

 

$

25,236

 

Less: Amounts capitalized to oil and gas properties

 

7,549

 

 

7,626

 

 

12,283

 

Total share-based compensation expense

$

18,418

 

$

14,462

 

$

12,953

 

 

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Note 12 — Income Taxes

Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Current income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(140

)

$

(2,180

)

$

18

 

State

 

739

 

 

103

 

 

58

 

Mexico

 

73

 

 

309

 

 

31

 

Total current income tax expense (benefit)

$

672

 

$

(1,768

)

$

107

 

 

 

 

 

 

 

 

Deferred income tax expense (benefit):

 

 

 

 

 

 

Federal

$

(94,409

)

$

(10,874

)

$

(61,182

)

State

 

(15,432

)

 

17,645

 

 

478

 

Mexico

 

—

 

 

—

 

 

—

 

Total deferred income tax expense (benefit)

$

(109,841

)

$

6,771

 

$

(60,704

)

 

 

 

 

 

 

 

Total income tax expense (benefit)

$

(109,169

)

$

5,003

 

$

(60,597

)

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Income tax expense (benefit) at the federal statutory tax rate

$

(126,944

)

 

21.0

 %

$

(14,992

)

 

21.0

 %

$

26,614

 

 

21.0

 %

State and local income taxes, net of federal benefit(1)

 

(14,849

)

 

2.5

 %

 

17,726

 

 

(24.8

)%

 

524

 

 

0.4

 %

Foreign tax effects

 

 

 

 

 

 

 

 

 

 

 

 

Mexico

 

 

 

 

 

 

 

 

 

 

 

 

Statutory tax rate difference between Mexico and U.S.

 

169

 

 

(0.0

)%

 

295

 

 

(0.4

)%

 

436

 

 

0.4

 %

Other

 

(565

)

 

0.1

 %

 

(671

)

 

0.9

 %

 

(1,452

)

 

(1.1

)%

Change in valuation allowance

 

28,800

 

 

(4.8

)%

 

—

 

 

—

 %

 

(93,726

)

 

(74.0

)%

Nontaxable or nondeductible items

 

2,848

 

 

(0.5

)%

 

4,925

 

 

(6.9

)%

 

4,419

 

 

3.5

 %

Effect of cross-border tax laws

 

395

 

 

(0.1

)%

 

620

 

 

(0.9

)%

 

1,016

 

 

0.8

 %

Change in unrecognized tax benefits

 

73

 

 

(0.0

)%

 

65

 

 

(0.1

)%

 

31

 

 

0.0

 %

Other adjustments

 

904

 

 

(0.1

)%

 

(2,965

)

 

4.2

 %

 

1,541

 

 

1.2

 %

Total income tax expense (benefit)

$

(109,169

)

 

18.1

 %

$

5,003

 

 

(7.0

)%

$

(60,597

)

 

(47.8

)%

Effective tax rate

 

18.1

 %

 

 

 

(7.0

)%

 

 

 

(47.8

)%

 

 

 

(1)
State and local taxes in Louisiana made up the majority (greater than 50%) of the tax effect in this category.

 

The Company’s effective tax rate for the year ended December 31, 2025 differed from the federal statutory rate of 21.0% primarily due to recording an income tax expense of $28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets offset with a state income tax benefit of $14.8 million.

The Company’s effective tax rate for the year ended December 31, 2024 differed from the federal statutory rate of 21.0% primarily due to state income tax expense of $17.7 million and income tax expense of $4.9 million related to nontaxable or nondeductible items.

The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $93.7 million related to the release of the valuation allowance for its federal deferred tax assets offset with income tax expense of $4.4 million related to nontaxable or nondeductible items.

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Deferred Tax Assets and Liabilities

Net deferred tax assets and liabilities reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Net deferred tax assets and liabilities is included in “Other liabilities” on the Consolidated Balance Sheets as of December 31, 2025. Significant components of deferred tax assets and liabilities were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

Deferred tax assets:

 

 

 

 

Federal net operating loss

$

139,330

 

$

108,717

 

Foreign tax loss carryforward

 

544

 

 

452

 

State net operating loss

 

16,359

 

 

12,426

 

Interest expense carryforward

 

40,177

 

 

74,957

 

Asset retirement obligations

 

302,222

 

 

262,773

 

Finance lease liability

 

25,389

 

 

29,926

 

Other

 

19,286

 

 

25,347

 

Total deferred tax assets

 

543,307

 

 

514,598

 

Valuation allowance

 

(32,735

)

 

(3,325

)

Total deferred tax assets, net

$

510,572

 

$

511,273

 

 

 

 

 

 

Deferred tax liabilities:

 

 

 

 

Oil and gas properties

$

656,457

 

$

772,439

 

Derivatives

 

10,851

 

 

5,411

 

Total deferred tax liabilities

 

667,308

 

 

777,850

 

Net deferred tax liability

$

(156,736

)

$

(266,577

)

 

Net Operating Loss

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2025 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + +

 

Amount

 

Expiration Year

Federal net operating losses

$

263,501

 

2036 - 2037

Federal net operating losses

$

399,976

 

Unlimited

Foreign tax loss carryforward

$

1,812

 

2026 - 2035

State net operating losses

$

373,383

 

Unlimited

 

As of December 31, 2025, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $663.5 million, $569.8 million of which are subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). Section 382 of the Code provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2036.

Valuation Allowance

The Company recorded a valuation allowance of $32.7 million and $3.3 million as of December 31, 2025 and 2024, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those NOLs or temporary differences relate. At December 31, 2025, the Company’s valuation allowance primarily related to the temporary differences related to the Company’s asset retirement obligations. At December 31, 2024, the company’s valuation allowance related to state operating loss carryforwards.

In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence.

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Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits.

Balances in the uncertain tax positions are as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Total unrecognized tax benefits, beginning balance

$

1,592

 

$

989

 

$

835

 

Increases in unrecognized tax benefits as a result of:

 

 

 

 

 

 

Tax positions taken during a prior period

 

277

 

 

(120

)

 

154

 

Tax positions taken during the current period

 

—

 

 

723

 

 

—

 

Total unrecognized tax benefits, ending balance

$

1,869

 

$

1,592

 

$

989

 

 

The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income Taxes Paid

The components of income taxes paid (net of refunds) were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Income taxes paid (net of refunds)

 

 

 

 

 

 

Federal (U.S.)

$

179

 

$

5,215

 

$

(18

)

Louisiana

 

418

 

 

1

 

 

—

 

Other

 

34

 

 

(297

)

 

12

 

Total income taxes paid (net of refunds)

$

631

 

$

4,919

 

$

(6

)

Years Open to Examination

The 2022 through 2025 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for years ending on or before December 31, 2020 are closed, except to the extent of any NOL carryover balance.

Note 13 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs and PSUs.

The following table presents the computation of the Company’s basic and diluted income (loss) per share attributable to common stockholders (in thousands, except for the per share amounts):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Net income (loss) attributable to Talos Energy Inc.

$

(494,290

)

$

(76,393

)

$

187,332

 

 

 

 

 

 

 

 

Weighted average common shares outstanding — basic

 

175,136

 

 

175,605

 

 

119,894

 

Dilutive effect of securities

 

—

 

 

—

 

 

858

 

Weighted average common shares outstanding — diluted

 

175,136

 

 

175,605

 

 

120,752

 

 

 

 

 

 

 

 

Net income (loss) per share attributable to common stockholders:

 

 

 

 

 

 

Basic

$

(2.82

)

$

(0.44

)

$

1.56

 

Diluted

$

(2.82

)

$

(0.44

)

$

1.55

 

Anti-dilutive potentially issuable securities excluded from diluted common shares

 

3,581

 

 

2,084

 

 

1,353

 

 

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Note 14 — Related Party Transactions

Slim Family and Affiliates

Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. In connection with the Company’s underwritten public equity offering in January 2024 as further described in Note 10 — Stockholders’ Equity, Control Empresarial further increased its holding of the Company’s outstanding stock and thereafter continued to purchase shares from time to time in the open market.

On December 16, 2024, the Company entered into a cooperation agreement (“Cooperation Agreement”) with Control Empresarial. Pursuant to the Cooperation Agreement, Control Empresarial agreed during the term of the Cooperation Agreement that it will not acquire, agree or seek to acquire or make any proposal or offer to acquire, or announce any intention to acquire, directly or indirectly, beneficially or otherwise, any voting securities of the Company (other than in connection with a stock split, stock dividend or similar corporate action initiated by the Company) if, immediately after such acquisition, Control Empresarial and the other members of its investor group, collectively, would, in the aggregate, beneficially own in aggregate more than 25.0% of the outstanding shares of any class of voting securities of the Company. However, pursuant to the Cooperation Agreement, Control Empresarial and the investor group are not required to sell any voting securities they own if the aggregate ownership exceeds 25.0% solely because the Company repurchases shares or takes another similar action that reduces the number of outstanding voting securities.

On December 8, 2025, the Company entered into an amendment to the Cooperation Agreement with Control Empresarial to extend the period of the Cooperation Agreement for an additional year, to December 16, 2026, but the agreement is subject to early termination upon the occurrence of certain events described in the Cooperation Agreement. Control Empresarial held approximately 25.8% of the Company’s outstanding shares of common stock as of December 31, 2025 based on SEC beneficial ownership reports filed by Control Empresarial and the Company’s total outstanding shares of common stock as of that date.

The Slim Family own a majority stake in Carso. Carso is a public stock company incorporated in Mexico, which holds the shares of a group of companies that primarily operate in the commercial, industrial, infrastructure and construction and energy sectors. Carso, through its Zamajal subsidiary, has an ownership interest in Talos Mexico. See Note 7 – Equity Method Investments for additional information on Talos Mexico. As of December 31, 2025, Carso owes the Company $2.8 million related to advisory services the Company provided in connection with the Lakach Deepwater natural gas field off Mexico’s southeastern coast near Veracruz.

Grupo Financiero Inbursa, S.A.B. de C.V. (“GFI”) is a Mexico-based holding company engaged, through its subsidiaries, in the financial sector. The company’s main activities are structured in four business lines: commercial banking, asset management, insurance and investment banking. The Slim Family own a majority stake in GFI. Banco Inbursa, S.A., Institución de Banca Múltiple, Grupo Financiero Inbursa (“Banco Inbursa”) is a wholly owned banking subsidiary of GFI.

In connection with the debt offering in February 2024, the Company consummated a firm commitment debt offering consisting of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the debt offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company paid Banco Inbursa, an advisory fee of approximately $2.7 million. See Note 8 – Debt for additional information regarding the issuance of the second-priority senior secured notes.

Equity Method Investments

The Company had a $0.7 million and $0.7 million related party receivable from various equity method investments as of December 31, 2025 and 2024, respectively. These amounts are reflected in “Accounts Receivable, net” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments.

Note 15 — Commitments and Contingencies

Legal Proceedings and Other Contingencies

From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.

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During the year ended December 31, 2024, the Company settled long-standing litigation initiated in June 2019 involving the former President of EnVen, which was assumed as part of the EnVen Acquisition. The Company paid $14.4 million to satisfy the judgment, inclusive of legal fees and interest.

By virtue of the Company’s acquisition of QuarterNorth, Talos is defending a lawsuit brought by a contractor concerning amounts allegedly owed for drilling operations at several locations in the Gulf of America. The lawsuit alleges that the contractor is entitled to certain statutory liens under Louisiana law. Talos disputes the contractor’s lien and damages claims and is defending the suit aggressively. A trial date has not been set for this case. It is reasonably possible that a loss may be realized, with the range of loss between zero and approximately $22 million.

By virtue of the Company’s acquisition of QuarterNorth, Talos is defending a lawsuit brought by plaintiffs (“Warrant Holders”) that held warrants issued by QuarterNorth pursuant and subject to warrant agreements. Warrant Holders allege that the QuarterNorth board improperly reduced the value of the warrants, which diluted their ownership interest in QuarterNorth prior to its acquisition by Talos. Trial is scheduled for May 2026, in the Court of Chancery of the State of Delaware. It is reasonably possible that a loss may be realized, with the range of loss between zero and approximately $21 million.

Firm Transportation Commitments

The Company has firm transportation agreements in place with pipeline carriers for future transportation of oil and gas production. The Company is obligated to transport a minimum monthly oil and gas volumes or pay for any deficiencies for years 2026 through 2030. Our production is currently expected to exceed the minimum monthly volume in the periods provided in the agreements.

The table below summarizes the future minimum transportation fees under the Company’s commitment as of December 31, 2025 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

2026

$

7,356

 

2027

 

11,760

 

2028

 

14,191

 

2029

 

7,468

 

2030

 

3,173

 

Total

$

43,948

 

 

Performance Obligations

Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, and removal of facilities in the U.S. Gulf of America.

As of December 31, 2025, the Company had secured performance bonds from third party sureties totaling $1.5 billion. The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2025, the Company had secured letters of credit issued under its Bank Credit Facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 8 — Debt for further information on the Bank Credit Facility.

On November 3, 2025, the Company entered into arrangements with its surety providers to establish limits on the amount of aggregate collateral that such surety providers can require the Company to post, with annual collateral funding commitments set forth in the table below. The arrangements also require the Company to spend a minimum amount on plugging and abandonment activities each year. For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, the Company is required to spend $90.0 million and $45.0 million on these activities on an annual basis, respectively.

The table below outlines the estimated collateral funding commitments under the arrangements as of December 31, 2025 (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + +

Period

Collateral Funding Commitments

 

2026

$

41,704

 

2027

 

42,694

 

2028

 

43,199

 

2029

 

42,134

 

2030

 

35,240

 

Thereafter

 

46,776

 

Total

$

251,747

 

 

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The collateral funding commitments may be secured by cash or letters of credit which will reduce the Company’s liquidity. For the year ended December 31, 2025, we posted collateral of $40.1 million secured by letters of credit. Collateral funded with cash will be reflected as “Restricted cash” within the Consolidated Balance Sheets. The collateral funding commitments, and ultimately any posted cash collateral, will be reduced as plugging and abandonment activities are completed and underlying surety bonds are released.

Decommissioning Obligations

The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of America, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Consolidated Statements of Operations.

The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Balance, beginning of period

$

20,002

 

$

15,564

 

$

54,269

 

Additions

 

1,769

 

 

6,168

 

 

266

 

Obligations assumed

 

—

 

 

1,326

 

 

—

 

Changes in estimate

 

1,476

 

 

2,391

 

 

11,613

 

Settlements

 

(1,102

)

 

(5,447

)

 

(50,584

)

Balance, end of period

$

22,145

 

$

20,002

 

$

15,564

 

Less: Current portion

 

470

 

 

5,453

 

 

3,280

 

Long-term portion

$

21,675

 

$

14,549

 

$

12,284

 

 

Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid.

Note 16 — Segment Information

The Company’s operations were managed through two operating segments through March 18, 2024: (i) the Upstream Segment and (ii) the CCS Segment, both of which were reportable for the year ended December 31, 2024. The CCS Segment was divested in March 2024.

Prior to the divestment of the CCS Segment, corporate general and administrative expense included certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that were not directly attributable to each operating segment. These shared expenses were fully allocated to each operating segment. Segment accounting policies are the same as those described in Note 2 – Summary of Significant Accounting Policies

The chief operating decision maker (“CODM”) is currently the President and Chief Executive Officer and Chief Financial Officer. The profit or loss metric used to evaluate segment performance is net income as reported in the Company’s Consolidated Statements of Operations. Net income is used by the CODM to measure segment profit or loss, assess performance and make strategic capital resource allocations. The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the tables below.

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The following tables present selected segment information for the periods indicated (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

Year Ended December 31, 2025

Upstream

 

Total

 

Revenues from external customers

$

1,780,070

 

$

1,780,070

 

Significant expenses:

 

 

 

 

Direct operating and maintenance(1)

 

(526,839

)

 

(526,839

)

Workover(1)

 

(19,877

)

 

(19,877

)

Adjusted general and administrative expense(2)

 

(133,986

)

 

(133,986

)

Net cash received (paid) on settled derivative instruments

 

81,471

 

 

81,471

 

Interest expense

 

(163,381

)

 

(163,381

)

Other segment items:

 

 

 

 

Other(3)

 

10,349

 

 

10,349

 

Depreciation, depletion and amortization

 

(1,056,281

)

 

(1,056,281

)

Impairment of oil and natural gas properties

 

(454,482

)

 

(454,482

)

Accretion expense

 

(125,296

)

 

(125,296

)

Mark-to-market derivative fair value gain (loss)

 

23,984

 

 

23,984

 

Equity-based compensation expense

 

(18,418

)

 

(18,418

)

Equity method investment income (loss)

 

(1,807

)

 

(1,807

)

Income tax benefit (expense)

 

109,169

 

 

109,169

 

Net income (loss)

 

(495,324

)

$

(495,324

)

 

 

 

 

 

Segment Expenditures

$

617,575

 

$

617,575

 

 

(1)
Component of lease operating expense.
(2)
Includes general and administrative expense less transaction expenses and equity-based compensation.
(3)
Primarily includes interest income and other miscellaneous operating income offset by the derecognition of a deferred payment that was deemed uncollectible.

 

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

Year Ended December 31, 2024

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,973,568

 

$

—

 

$

1,973,568

 

Significant expenses:

 

 

 

 

 

 

Direct operating and maintenance(2)

 

(492,123

)

 

—

 

 

(492,123

)

Workover(2)

 

(73,918

)

 

—

 

 

(73,918

)

Adjusted general and administrative expense(3)

 

(130,695

)

 

(1,919

)

 

(132,614

)

Net cash received (paid) on settled derivative instruments

 

4,710

 

 

—

 

 

4,710

 

Interest expense

 

(187,432

)

 

(206

)

 

(187,638

)

Other segment items:

 

 

 

 

 

 

Other(4)

 

(23,048

)

 

(8,472

)

 

(31,520

)

Depreciation, depletion and amortization

 

(1,023,512

)

 

(46

)

 

(1,023,558

)

Accretion expense

 

(117,604

)

 

—

 

 

(117,604

)

Mark-to-market derivative fair value gain (loss)

 

(6,168

)

 

—

 

 

(6,168

)

Equity-based compensation expense

 

(14,415

)

 

(47

)

 

(14,462

)

Gain on TLCS Divestiture(5)

 

—

 

 

100,482

 

 

100,482

 

Equity method investment income (loss)

 

(2,319

)

 

(7,970

)

 

(10,289

)

Gain (loss) on extinguishment of debt

 

(60,256

)

 

—

 

 

(60,256

)

Income tax benefit (expense)

 

12,188

 

 

(17,191

)

 

(5,003

)

Net income (loss)

$

(141,024

)

$

64,631

 

$

(76,393

)

 

 

 

 

 

 

 

Segment Expenditures

$

603,765

 

$

17,519

 

$

621,284

 

 

(1)
The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
(2)
Component of lease operating expense.
(3)
Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $78.5 million and $0.4 million, respectively.
(4)
Primarily includes transaction expenses offset by interest income for the Upstream Segment and transaction expenses for the CCS Segment. Transaction expenses include severance expense, costs related to the QuarterNorth Acquisition and costs related to the TLCS Divestiture. See further discussion in Note 3 — Acquisition and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation.
(5)
See further discussion in Note 3 — Acquisitions and Divestitures for additional information.
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+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

Year Ended December 31, 2023

Upstream

 

CCS(1)

 

Total

 

Revenues from external customers

$

1,457,886

 

$

—

 

$

1,457,886

 

Significant expenses:

 

 

 

 

 

 

Direct operating and maintenance(2)

 

(374,481

)

 

—

 

 

(374,481

)

Workover(2)

 

(15,140

)

 

—

 

 

(15,140

)

Adjusted general and administrative expense(3)

 

(88,333

)

 

(10,423

)

 

(98,756

)

Net cash received (paid) on settled derivative instruments

 

(9,457

)

 

—

 

 

(9,457

)

Interest expense

 

(172,060

)

 

(1,085

)

 

(173,145

)

Other segment items:

 

 

 

 

 

 

Other(4)

 

(55,048

)

 

4,159

 

 

(50,889

)

Depreciation, depletion and amortization

 

(661,904

)

 

(1,630

)

 

(663,534

)

Accretion expense

 

(86,152

)

 

—

 

 

(86,152

)

Mark-to-market derivative fair value gain (loss)

 

90,385

 

 

—

 

 

90,385

 

Equity-based compensation expense

 

(11,454

)

 

(1,499

)

 

(12,953

)

Gain on the 2023 Mexico Divestiture(5)

 

66,180

 

 

—

 

 

66,180

 

Equity method investment income (loss)

 

120

 

 

(12,229

)

 

(12,109

)

Gain (loss) on partial sale of equity investment(6)

 

—

 

 

8,900

 

 

8,900

 

Income tax benefit (expense)

 

57,719

 

 

2,878

 

 

60,597

 

Net income (loss)

$

198,261

 

$

(10,929

)

$

187,332

 

 

 

 

 

 

 

 

Segment Expenditures

$

733,669

 

$

40,961

 

$

774,630

 

 

(1)
The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
(2)
Component of lease operating expense.
(3)
Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $49.3 million and $1.7 million, respectively.
(4)
Primarily includes transaction expenses and decommissioning obligations for the Upstream Segment. Transaction expenses include costs related to the EnVen Acquisition, inclusive of severance expense. See further discussion in Note 3 — Acquisition and Divestitures, Note 11 — Employee Benefits Plans and Share-Based Compensation and Note 15 — Commitments and Contingencies.
(5)
See further discussion in Note 3 — Acquisitions and Divestitures for additional information.
(6)
Includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million. See further discussion in Note 7 — Equity Method Investments.

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Segment Expenditures:

 

 

 

 

 

 

Total reportable segments

$

617,575

 

$

621,284

 

$

774,630

 

Change in capital expenditures included in accounts payable and accrued liabilities

 

829

 

 

29,423

 

 

(9,199

)

Plugging & abandonment

 

(117,847

)

 

(108,789

)

 

(86,615

)

Decommissioning obligations settled

 

(1,102

)

 

(5,447

)

 

(50,584

)

Investment in Talos Mexico

 

(4,559

)

 

(5,469

)

 

—

 

Investment in CCS intangibles and equity method investees

 

—

 

 

(17,519

)

 

(40,946

)

Other deferred payments

 

(2,104

)

 

(2,389

)

 

(1,545

)

Non-cash well equipment transfers

 

(15,837

)

 

(3,412

)

 

(27,731

)

Other

 

4,950

 

 

1,232

 

 

3,424

 

Exploration, development and other capital expenditures

$

481,905

 

$

508,914

 

$

561,434

 

 

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Note 17 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depreciation, depletion and amortization (“DD&A”) as of the dates indicated are presented below (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Proved properties

$

10,621,012

 

$

9,784,832

 

$

7,906,295

 

Unproved oil and gas properties, not subject to amortization

 

480,555

 

 

587,238

 

 

268,315

 

Total oil and gas properties

 

11,101,567

 

 

10,372,070

 

 

8,174,610

 

Less: Accumulated DD&A

 

6,672,024

 

 

5,163,844

 

 

4,143,491

 

Net capitalized costs

$

4,429,543

 

$

5,208,226

 

$

4,031,119

 

DD&A rate (Per Boe)

$

30.51

 

$

30.11

 

$

27.23

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Unproved oil and gas properties, not subject to amortization

$

62,528

 

$

58,723

 

$

56,579

 

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional information.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Property acquisition costs:

 

 

 

 

 

 

Proved properties

$

62,689

 

$

1,085,324

 

$

951,703

 

Unproved properties, not subject to amortization

 

—

 

 

380,129

 

 

249,688

 

Total property acquisition costs

 

62,689

 

 

1,465,453

 

 

1,201,391

 

Exploration costs

 

54,647

 

 

129,400

 

 

161,296

 

Development costs

 

618,441

 

 

602,607

 

 

805,148

 

Total costs incurred

$

735,777

 

$

2,197,460

 

$

2,167,835

 

 

 

 

 

 

 

 

Company's Share of Equity Investees:

 

 

 

 

 

 

Exploration costs

$

3,805

 

$

2,144

 

$

290

 

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of America.

At December 31, 2025 and 2024 all proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), independent petroleum engineers and geologists. At December 31, 2023, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by NSAI.

+

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+
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+

 

+

The following table presents the Company’s estimated proved reserves at its net ownership interest:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + + + + +

 

Oil (MBbls)

 

Gas (MMcf)

 

NGLs (MBbls)

 

Oil Equivalent
(MBoe)

 

Consolidated Entities:

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2022

 

91,059

 

 

219,551

 

 

12,928

 

 

140,579

 

Revision of previous estimates

 

(6,308

)

 

(62,946

)

 

(1,283

)

 

(18,082

)

Production

 

(18,062

)

 

(26,194

)

 

(1,767

)

 

(24,195

)

Acquisition of reserves

 

41,871

 

 

36,690

 

 

1,116

 

 

49,102

 

Extensions and discoveries

 

2,255

 

 

12,770

 

 

979

 

 

5,362

 

Total proved reserves at December 31, 2023

 

110,815

 

 

179,871

 

 

11,973

 

 

152,766

 

Revision of previous estimates

 

(599

)

 

(30,186

)

 

698

 

 

(4,932

)

Production

 

(24,078

)

 

(41,078

)

 

(2,969

)

 

(33,893

)

Acquisition of reserves

 

51,376

 

 

99,683

 

 

4,834

 

 

72,824

 

Extensions and discoveries

 

5,534

 

 

9,684

 

 

329

 

 

7,477

 

Total proved reserves at December 31, 2024

 

143,048

 

 

217,974

 

 

14,865

 

 

194,242

 

Revision of previous estimates

 

3,944

 

 

15,826

 

 

(686

)

 

5,896

 

Production

 

(24,065

)

 

(46,122

)

 

(2,782

)

 

(34,534

)

Acquisition of reserves

 

7,232

 

 

2,573

 

 

10

 

 

7,670

 

Extensions and discoveries

 

467

 

 

4,349

 

 

227

 

 

1,419

 

Total proved reserves at December 31, 2025

 

130,626

 

 

194,600

 

 

11,634

 

 

174,693

 

Total Proved Developed Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2023

 

98,225

 

 

141,823

 

 

9,957

 

 

131,819

 

December 31, 2024

 

108,479

 

 

175,139

 

 

12,733

 

 

150,402

 

December 31, 2025

 

101,031

 

 

156,420

 

 

9,644

 

 

136,745

 

Total Proved Undeveloped Reserves as of:

 

 

 

 

 

 

 

 

December 31, 2023

 

12,590

 

 

38,048

 

 

2,016

 

 

20,947

 

December 31, 2024

 

34,569

 

 

42,835

 

 

2,132

 

 

43,840

 

December 31, 2025

 

29,595

 

 

38,180

 

 

1,990

 

 

37,948

 

During 2025, proved reserves decreased by 19.5 MMBoe primarily due to 34.5 MMBoe of production. This decrease was partially offset by the acquisition of reserves of 7.7 MMBoe in connection with the incremental working interests in the Monument Project and certain Mississippi Canyon blocks as discussed in Note 3 — Acquisitions and Divestitures as well as an increase of 5.9 MMBoe from revisions of previous estimates. The revisions were due to certain upward revisions for positive well performance primarily in the Katmai Field combined with the Lobster Field, and from the Venice and Lime Rock wells, which tie back to our Ram Powell facility. These upward revisions were partially offset by the derecognition of approximately 2.0 MMBoe of PUD reserves associated with our South Timbalier 308 Field in the Shelf (i.e., water depths up to 600 feet) area, resulting from a reassessment of the drilling and development plan following successful drilling at the Katmai Field.

During 2024, proved reserves increased by 41.5 MMBoe primarily due to the acquisition of reserves of 72.8 MMBoe in connection with the QuarterNorth Acquisition and the Monument Project as well as 7.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field, Ewing Bank 953 Field, Sunspear Field and Pompano Field in the Deepwater area. This increase was partially offset by 33.9 MMBoe of production and a decrease of 4.9 MMBoe from revisions of previous estimates. The revisions were primarily due to a 11.3 MMBoe of downward revisions primarily related to derecognizing proved developed non-producing and PUD cases in the Phoenix Field, Brutus Field and Prince Field, all located in the Deepwater area. Additionally, due to the Deepwater assets acquired via the QuarterNorth Acquisition and the Monument Project, the Company reassessed its drilling and development plan resulting in the derecognition of 4.2 MMBoe of PUD reserves primarily associated non-operated fields located in the Shelf & Gulf Coast area. These downward revisions were offset by upward revisions 15.3 MMBoe due to the successful drilling of the Katmai West #2 development well in addition to positive well performance primarily in the Katmai Field and Big Bend Field located in the Deepwater area.

During 2023, proved reserves increased by 12.2 MMBoe primarily due to acquisition of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Deepwater area. This increase was partially offset by 24.2 MMBoe of production and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Deepwater area due to well performance.

 

+

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+

 

+

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Future cash inflows

$

9,465,575

 

$

11,660,546

 

$

9,425,055

 

Future costs:

 

 

 

 

 

 

Production

 

(2,954,861

)

 

(3,436,232

)

 

(3,090,491

)

Development and abandonment

 

(2,901,567

)

 

(3,301,619

)

 

(2,358,368

)

Future net cash flows before income taxes

 

3,609,147

 

 

4,922,695

 

 

3,976,196

 

Future income tax expense

 

(519,461

)

 

(845,894

)

 

(589,413

)

Future net cash flows after income taxes

 

3,089,686

 

 

4,076,801

 

 

3,386,783

 

Discount at 10% annual rate

 

(284,829

)

 

(512,597

)

 

(343,295

)

Standardized measure of discounted future net cash flows

$

2,804,857

 

$

3,564,204

 

$

3,043,488

 

 

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Oil price per Bbl

$

65.37

 

$

75.51

 

$

78.56

 

Natural gas price per Mcf

$

3.61

 

$

2.45

 

$

2.75

 

NGL price per Bbl

$

19.22

 

$

21.91

 

$

18.77

 

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Consolidated Entities:

 

 

 

 

 

 

Standardized measure, beginning of year

$

3,564,204

 

$

3,043,488

 

$

4,368,448

 

Sales and transfers of oil, net gas and NGLs produced during the period

 

(1,232,936

)

 

(1,406,150

)

 

(1,065,814

)

Net change in prices and production costs

 

(946,617

)

 

(123,537

)

 

(2,835,125

)

Changes in estimated future development and abandonment costs

 

72,525

 

 

193,810

 

 

(19,877

)

Previously estimated development and abandonment costs incurred

 

183,066

 

 

47,016

 

 

202,503

 

Accretion of discount

 

420,072

 

 

485,409

 

 

518,110

 

Net change in income taxes

 

252,340

 

 

(181,190

)

 

357,321

 

Purchases of reserves

 

143,040

 

 

1,638,000

 

 

2,033,852

 

Extensions and discoveries

 

7,250

 

 

74,126

 

 

90,244

 

Net change due to revision in quantity estimates

 

403,358

 

 

(162,041

)

 

(484,423

)

Changes in production rates (timing) and other

 

(61,445

)

 

(44,727

)

 

(121,751

)

Standardized measure, end of year

$

2,804,857

 

$

3,564,204

 

$

3,043,488

 

 

+

F-41

+
+

Table of Contents

+

 

+

Note 18 — Subsequent Events

Amended and Restated Credit Agreement

For additional information, see Note 8 — Debt.

 

 

 

+

F-42

+
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Table of Contents

+

 

+

Schedule I. Condensed Financial Information of Registrant

TALOS ENERGY INC. (PARENT ONLY)

BALANCE SHEETS

(In thousands, except share amounts)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

ASSETS

 

 

 

 

Current assets:

 

 

 

 

Prepaid assets

$

—

 

$

203

 

Other current assets

 

179

 

 

19

 

Total current assets

 

179

 

 

222

 

Other long-term assets:

 

 

 

 

Investments in subsidiaries

 

2,321,449

 

 

3,006,909

 

Total assets

$

2,321,628

 

$

3,007,131

 

LIABILITIES AND STOCKHOLDERSʼ EQUITY

 

 

 

 

Current liabilities:

 

 

 

 

Accounts payable

$

40

 

$

333

 

Accrued liabilities

 

567

 

 

544

 

Other current liabilities

 

1,058

 

 

162

 

Total current liabilities

 

1,665

 

 

1,039

 

Long-term liabilities:

 

 

 

 

Other long-term liabilities

 

151,979

 

 

246,387

 

Total liabilities

 

153,644

 

 

247,426

 

Commitments and contingencies (Note 15)

 

 

 

 

Stockholdersʼ equity:

 

 

 

 

Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2025 and 2024, respectively

 

—

 

 

—

 

Common stock; $0.01 par value; 270,000,000 shares authorized; 188,530,052 and 187,434,908 shares issued as of December 31, 2025 and 2024, respectively

 

1,885

 

 

1,874

 

Additional paid-in capital

 

3,296,643

 

 

3,274,626

 

Accumulated deficit

 

(918,400

)

 

(424,110

)

Treasury stock, at cost; 20,015,369 and 7,417,385 shares as of December 31, 2025 and 2024, respectively

 

(212,144

)

 

(92,685

)

Total stockholdersʼ equity

 

2,167,984

 

 

2,759,705

 

Total liabilities and stockholdersʼ equity

$

2,321,628

 

$

3,007,131

 

 

+

See accompanying notes.

 

F-43

+
+

Table of Contents

+

 

+

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF OPERATIONS

(In thousands)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

 

2025

 

2024

 

2023

 

Operating expenses:

 

 

 

 

 

 

General and administrative expense

$

3,605

 

$

3,234

 

$

2,708

 

Total operating expenses

 

3,605

 

 

3,234

 

 

2,708

 

Operating income (expense)

 

(3,605

)

 

(3,234

)

 

(2,708

)

Other income (expense)

 

(1

)

 

(1

)

 

(1

)

Equity earnings (loss) from subsidiaries

 

(585,315

)

 

(83,986

)

 

128,888

 

Net income (loss) before income taxes

 

(588,921

)

 

(87,221

)

 

126,179

 

Income tax benefit (expense)

 

94,631

 

 

10,828

 

 

61,153

 

Net income (loss)

$

(494,290

)

$

(76,393

)

$

187,332

 

 

+

See accompanying notes.

 

F-44

+
+

Table of Contents

+

 

+

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF CASH FLOWS

(In thousands)

+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + +
+ + + + + + + + + +

 

Year Ended December 31,

 

2025

 

2024

 

2023

 

Cash flows from operating activities:

 

 

 

 

 

 

Net cash provided by (used in) operating activities

$

(1,399

)

$

(1,403

)

$

(1,836

)

Cash flows from investing activities:

 

 

 

 

 

 

Investments in subsidiaries

 

—

 

 

(389,138

)

 

—

 

Distributions from subsidiaries

 

120,858

 

 

48,005

 

 

49,340

 

Net cash provided by (used in) investing activities

 

120,858

 

 

(341,133

)

 

49,340

 

Cash flows from financing activities:

 

 

 

 

 

 

Issuance of common stock

 

—

 

 

387,717

 

 

—

 

Purchase of treasury stock

 

(119,459

)

 

(45,181

)

 

(47,504

)

Net cash provided (used in) by financing activities

 

(119,459

)

 

342,536

 

 

(47,504

)

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

—

 

 

—

 

 

—

 

Cash and cash equivalents:

 

 

 

 

 

 

Balance, beginning of period

 

—

 

 

—

 

 

—

 

Balance, end of period

$

—

 

$

—

 

$

—

 

 

+

See accompanying notes.

 

F-45

+
+

Table of Contents

+

 

+

+TALOS ENERGY INC. (PARENT ONLY)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2025

Note 1 — Basis of Presentation

Pursuant to the rules and regulations of the SEC, the parent only condensed financial information of Talos Energy, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Schedules in this Annual Report.

+

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+
+ + diff --git a/tests/fixtures/html/vnom/10k/vnom-10-k-2026-02-25.html b/tests/fixtures/html/vnom/10k/vnom-10-k-2026-02-25.html new file mode 100644 index 000000000..99e24a821 --- /dev/null +++ b/tests/fixtures/html/vnom/10k/vnom-10-k-2026-02-25.html @@ -0,0 +1,8 @@ + + + + + + + +vnom-20251231
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-42807
Viper Energy, Inc.
(Exact name of registrant as specified in its charter)

DE
39-2596878
State or other jurisdiction of incorporation or organization
(I.R.S. Employer Identification No.)
500 West Texas Ave.,
Suite 100
Midland,TX
79701
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code (432) 221-7400

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class A Common Stock, $0.000001 Par Value
VNOMThe Nasdaq Stock Market LLC
(NASDAQ Global Select Market)
Securities registered pursuant to section 12(g) of the Act:
None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2025, was approximately $5.0 billion.
As of February 20, 2026, 176,723,281 shares of Class A Common Stock and 180,825,588 shares of Class B Common Stock of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of Viper Energy, Inc.’s Proxy Statement for the 2026 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.


VIPER ENERGY, INC.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2025

TABLE OF CONTENTS

Page

i
Table of Contents
GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K (the “Annual Report” or this “report”):

Argus WTI MidlandGrade of oil that serves as a benchmark price for oil at Midland, Texas.
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOOne barrel of crude oil.
BO/dOne BO per day.
BOEOne barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dOne BOE per day.
British Thermal UnitThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
CondensateLiquid hydrocarbons associated with the production that is primarily natural gas.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Deterministic methodThe method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreageAcreage allocated or assignable to productive wells.
Development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
Development wellA well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
DifferentialAn adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry holeA well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
ExploitationA development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
FieldAn area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding costsCapital costs incurred in the acquisition of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Formation
A layer of rock which has distinct characteristics that differs from nearby rock.
FracturingThe process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross royalty acres or gross wells
The total acres or wells in which a mineral interest is owned.
Henry HubNatural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
Horizontal drillingA drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Horizontal wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBblsOne thousand barrels of crude oil and other liquid hydrocarbons.
MBOEOne thousand BOE, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MBOE/dOne thousand BOE per day.
McfOne thousand cubic feet of natural gas.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuOne million British Thermal Units.
MMcfMillion cubic feet of natural gas.
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Table of Contents
Net mineral acres
The portion of total mineral rights a person or entity owns in a tract of land, calculated by multiplying the gross royalty acres in such tract by such person or entity’s fractional ownership interest.
Net revenue interestAn owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding interests and other burdens.
Net royalty acresNet mineral acres multiplied by the average lease royalty interest and other burdens.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Plugging and abandonmentRefers to the sealing off of fluids in the reservoir penetrated by a well so that the fluids from one reservoir will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive wellA well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
ProspectA specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercially recoverable hydrocarbons.
Proved developed reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reservesThe estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves or PUDsProved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
RecompletionThe process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
ReservesReserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource playA set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
SpacingThe distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
SpudCommencement of actual drilling operations.
Standardized measureThe present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Tight formationA formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Undeveloped acreageLease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Waha HubNatural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.
WellboreThe hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
Working interestAn operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTIWest Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil that serves as a benchmark for oil on the NYMEX.
WTI CushingGrade of oil that serves as a benchmark price for oil at Cushing, Oklahoma.
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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms used in this report:

Adjusted EBITDA
Consolidated Adjusted EBITDA, a non-GAAP measure, generally equals net income (loss) attributable to Viper Energy, Inc. plus net income (loss) attributable to non-controlling interest before interest expense, net, non-cash share-based compensation expense, depletion, impairment, non-cash (gain) loss on derivative instruments, (gain) loss on extinguishment of debt, other non-cash operating expenses, other non-recurring expenses, if any, and provision for (benefit from) income taxes.
ASUAccounting Standards Update.
Class A Common Stock
After August 19, 2025, Class A common stock, $0.000001 par value per share of New Viper (as defined below), and before August 19, 2025, Class A common stock, $0.000001 par value per share of Former Viper (as defined below).
Class B Common Stock
After August 19, 2025, Class B common stock, $0.000001 par value per share of New Viper, and before August 19, 2025, Class B common stock, $0.000001 par value per share of Former Viper.
Common StockCollectively, Class A Common Stock and Class B Common Stock.
ConversionThe transaction, effective November 13, 2023, whereby the Partnership converted from a Delaware limited partnership to a Delaware corporation known as “Viper Energy, Inc.”
DiamondbackDiamondback Energy, Inc., a Delaware corporation.
Diamondback E&P LLCA subsidiary of Diamondback.
EPAUnited States Environmental Protection Agency.
Exchange ActThe Securities Exchange Act of 1934, as amended.
FASBFinancial Accounting Standards Board.
FERCFederal Energy Regulatory Commission.
GAAPAccounting principles generally accepted in the United States.
General PartnerViper Energy Partners GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly owned subsidiary of Diamondback prior to the Conversion.
Guaranteed Senior Notes
The outstanding senior notes of Viper Energy Partners LP (f/k/a Viper Energy Partners LLC), issued under indentures where Viper Energy, Inc. and VNOM Sub, Inc., a wholly owned subsidiary of Viper Energy, Inc., are the guarantors, consisting of the 4.900% Senior Notes due 2030 and the 5.700% Senior Notes due 2035.
LTIPViper Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended and restated by Viper Energy, Inc. 2024 Amended and Restated Long-Term Incentive Plan, and as may be further amended or restated from time to time.
NasdaqThe Nasdaq Global Select Market.
Net debtNet debt, a non-GAAP measure, is debt (excluding debt issuance costs, discounts and premiums) less cash and cash equivalents.
Notes
Those senior notes of Viper Energy, Inc. that were issued under indentures where Viper Energy Partners LLC and other subsidiaries were guarantors, consisting of the 5.375% Senior Notes due 2027 and the 7.375% Senior Notes due 2031, and which were redeemed on November 1, 2025 and July 23, 2025, respectively.
NYMEXNew York Mercantile Exchange.
OPECOrganization of the Petroleum Exporting Countries.
Operating Company or OpCoPrior to December 23, 2025, Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy, Inc. and after December 23, 2025, VNOM Holding Company LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy, Inc.
OpCo Unit
Limited liability company membership interest in the Operating Company.
Partnership
Viper Energy Partners LP, the predecessor of the Company (as defined below), which converted into the Company in the Conversion.
Partnership AgreementThe second amended and restated agreement of limited partnership of the Partnership, dated as of May 9, 2018, as amended as of May 10, 2018, and further amended on November 2, 2023.
Ryder ScottRyder Scott Company, L.P.
SECUnited States Securities and Exchange Commission.
SEC PricesUnweighted arithmetic average of the first-day-of-the-month price for each month during the 12-month period prior to the ending date of the period covered by this report.
Securities ActThe Securities Act of 1933, as amended.
SOFRThe secured overnight financing rate.
Wells FargoWells Fargo Bank, National Association.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow and financial position; production levels on properties in which we have mineral and royalty interests; developmental activity by other operators; reserve estimates and our ability to replace or increase reserves; anticipated benefits or other effects of strategic transactions; and plans and objectives of management (including Diamondback’s plans for developing our acreage, our cash dividend policy and repurchases of our Common Stock, OpCo Units or Guaranteed Senior Notes) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to us are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although we believe that the expectations and assumptions reflected in our forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond our control. Accordingly, forward-looking statements are not guarantees of our future performance and the actual outcomes could differ materially from what we expressed in our forward-looking statements.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following:

•changes in supply and demand levels for oil, natural gas and natural gas liquids and the resulting impact on the price for those commodities;
•the impact of public health crises, including epidemic or pandemic diseases and any related company or government policies or actions;
•actions taken by the members of OPEC and its non-OPEC allies (“OPEC+”) affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;
•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates, or instability in the financial sector;
•regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
•physical and transition risks relating to climate change and changing political and social perspectives on climate change and other ESG (as defined below) factors;
•risks from our cash dividend policy and uncertainties over our future dividends;
•restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;
•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;
•changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions;
•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our limited number of operators and our ability to replace operators in time of bankruptcy or default;
•changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators;
•the inherent uncertainties over our estimated reserves, the development of our proved undeveloped reserves or the yield from project areas on our properties;
•the geographical concentration of our producing properties and reserves in the Permian Basin and in a small number of producing horizons;
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•changes in safety, health, environmental, tax and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change);
•security threats, including cybersecurity threats and disruptions to our business from breaches of Diamondback’s information technology systems, or from breaches of information technology systems of our operators or third parties with whom we transact business;
•lack of, or disruption in, access to adequate and reliable electrical power, internet and telecommunication infrastructure, information and computer systems, transportation, processing, storage and other facilities impacting our operators;
•severe weather conditions and natural disasters;
•geopolitics, regional conflicts, acts of war or terrorist acts and the governmental or military response thereto;
•changes in the financial strength of counterparties to the credit facility and hedging contracts of our operating subsidiary;
•our substantial indebtedness and changes in our credit rating;
•failure to develop or acquire additional reserves and identify, complete or integrate acquisitions;
•our operational dependence on, and control by, Diamondback and potential conflicts of interest thereof; and
•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.

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PART I

On November 13, 2023, Viper Energy Partners LP converted from a Delaware limited partnership to a Delaware corporation named “Viper Energy, Inc.” (the “Conversion”).

On August 19, 2025, upon completion of the Sitio Acquisition (as defined and discussed below), Viper Energy, Inc. changed its name to VNOM Sub, Inc. (“Former Viper”) and became a wholly owned subsidiary of New Cobra Pubco, Inc., which subsequently changed its name to Viper Energy, Inc., (“New Viper”), as a result of a merger contemplated by the documents governing the Sitio Acquisition (such merger, the “Viper PubCo Merger”).

On December 23, 2025, the Company completed an internal reorganization (the “Reorganization”), pursuant to which, among other things, each outstanding OpCo Unit of Viper Energy Partners LLC, a Delaware limited liability company and Viper’s operating subsidiary (“Old OpCo”), was converted into an equivalent OpCo Unit issued by a newly-formed subsidiary of Viper, VNOM Holding Company LLC (“New OpCo”).

References in this Annual Report to “Viper” refer to (A) New Viper following the Viper PubCo Merger (B) Former Viper prior to the Viper PubCo Merger but after the Conversion, and (C) Viper Energy Partners LP prior to the Conversion. References to the “Company,” “our company,” “we,” “our,” “us” or like terms refer collectively to Viper and its consolidated subsidiaries. References to “shares” or per share amounts prior to the Conversion refer to common units and Class B units or per unit amounts of Viper Energy Partners LP. References to shares or per share amounts following the Conversion refer to (A) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of New Viper following the Viper PubCo Merger and (B) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of Former Viper prior to the Viper PubCo Merger.

References to the “Operating Company” or “OpCo” refer to (A) New OpCo following the Reorganization and (B) Old OpCo prior to the Reorganization. References to “OpCo Units” refer to the units representing limited liability company interests in the Operating Company.

References to “Diamondback” refer collectively to Diamondback Energy, Inc. and its subsidiaries other than the Company. References to the “General Partner” refer to Viper Energy Partners GP LLC, our general partner prior to the Conversion. All references to dividends prior to the Conversion refer to distributions.

See Note 1—Organization and Basis of Presentation in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of the Conversion.

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Overview

We are a publicly traded Delaware corporation focused on owning and acquiring mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment. Effective November 13, 2023, we converted our legal status from a Delaware limited partnership into a Delaware corporation. Our primary business objective is to provide an attractive return to our stockholders by focusing on business results, generating robust free cash flow, reducing debt and protecting our balance sheet, while maintaining what we believe is a best-in-class cost structure. Our assets consist of mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin in West Texas, substantially all of which are leased to working interest owners who bear the costs of operation and development.

We are currently focused on oil and natural gas properties primarily in the Permian Basin, which is one of the oldest and most prolific producing basins in North America. The Permian Basin, which consists of approximately 75,000 square miles centered around Midland, Texas, has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of formations of oil and natural gas bearing rock throughout.

Non-Permian Divestiture and Significant Acquisitions

Divestiture of Non-Permian Assets

On February 9, 2026, we divested all of our non-Permian assets, including those acquired from Sitio Royalties Corp. (“Sitio”), to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments (the “Non-Permian Divestiture”). The divested properties consisted
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of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d.

Sitio Acquisition

On August 19, 2025, we completed a series of transactions in which New Viper acquired Sitio, Sitio Royalties Operating Partnership, LP (“Sitio OpCo”) and their respective subsidiaries, pursuant to the Agreement and Plan of Merger, dated June 2, 2025, by and among Former Viper, the Operating Company, Sitio, Sitio OpCo, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (the “Sitio Acquisition”). The Sitio Acquisition was an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

2025 Drop Down

On May 1, 2025, we acquired all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC from Endeavor Energy Resources, LP (“Endeavor”), each a seller party and a subsidiary of Diamondback, pursuant to a definitive equity purchase agreement for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of our Class B Common Stock (the “2025 Drop Down”). The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further information.

Our Properties

As of December 31, 2025, our assets consisted of mineral interests and royalty interests underlying approximately 4,462,119 gross royalty acres and 96,003 net royalty acres primarily in the Permian Basin, and Diamondback was the operator of approximately 35% of our net royalty acreage. As of December 31, 2025, there were 43,355 gross productive wells on this acreage, 6,524 of which were operated by Diamondback. Net production during the fourth quarter of 2025 was approximately 134,000 BOE/d and net production for the year ended December 31, 2025, averaged 95,126 BOE/d. For the years ended December 31, 2025, 2024 and 2023, royalty income generated from these mineral and royalty interests was $1.3 billion, $854 million and $717 million, respectively.

At December 31, 2025, our estimated proved oil and natural gas reserves totaled 406,035 MBOE based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. As of December 31, 2025, approximately 78% of our proved reserves were classified as proved developed producing reserves. PUD included in this estimate were from 1,653 gross horizontal well locations. As of December 31, 2025, our proved reserves were approximately 48% oil, 26% natural gas and 26% natural gas liquids.

Our Relationship with Diamondback

As of December 31, 2025, Diamondback beneficially owned 155,058,093 shares of our outstanding Class B Common Stock, representing approximately 42.1% of the then outstanding voting power of our capital stock on a fully diluted basis, after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report). We believe Diamondback’s significant ownership in us may motivate it to offer additional mineral and other interests in oil and natural gas properties to us in the future, although Diamondback has no obligation to do so and may elect to hold or dispose of mineral and other interests in such properties without offering us the opportunities to acquire them.

We believe Diamondback views our company as part of its business strategy and that Diamondback may be incentivized to pursue additional acquisitions jointly with us in the future. However, Diamondback will regularly evaluate acquisitions and may elect to acquire properties without offering us the opportunity to participate in such transactions. Moreover, Diamondback may not be successful in identifying potential acquisitions. Diamondback is free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with acquisition or disposition opportunities.

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In addition, neither we nor our Operating Company have any employees. Diamondback provides management, operating and administrative services to us under the services and secondment agreement (the “Services and Secondment Agreement”), including the services of the executive officers and other employees. For additional information, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes in Item 8. Financial Statements and Supplementary Data of this report.

Business Strategies

Our primary business objective is to generate the highest value proposition for our stockholders through a focus on increasing long-term per share growth and returns by generating robust free cash flow, managing our capital structure, including reducing debt, and protecting our balance sheet. We intend to accomplish this objective by executing the following strategies:

•Capitalize on the development of the properties underlying our mineral interests to grow our cash flow. We expect the production from our mineral interests will increase as Diamondback and our other operators continue to develop our acreage by drilling and completing wells. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated increase in our aggregate royalty payment receipts will enable us to grow our cash flows.

•Leverage our relationship with Diamondback to participate with it in acquisitions of mineral or other interests in producing properties from third parties and to increase the size and scope of our potential third-party acquisition targets. We have in the past and intend to continue to make opportunistic acquisitions of mineral and other interests that have substantial oil-weighted resource potential and organic growth potential. Through our relationships with Diamondback and its affiliates, we have access to their significant pool of management talent and industry relationships, which we believe provide us with a competitive advantage in pursuing potential third-party acquisition opportunities. For example, we and Diamondback may pursue an acquisition where Diamondback acquires working and revenue interests in properties and we acquire mineral, royalty or overriding royalty interests in such properties either in the same or subsequent transactions.

•Seek to acquire from Diamondback or unaffiliated third parties, from time to time, mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria. Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral or other interests in producing oil and natural gas properties directly from Diamondback as well as from unaffiliated third parties. We believe Diamondback may continue to be incentivized to sell properties to us, as doing so may enhance Diamondback’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through dividends on Diamondback’s controlling interests in us. However, neither Diamondback nor any of its affiliates are contractually or otherwise obligated to offer or sell any interests in properties to us. We also may seek to acquire mineral or other interests in producing oil and natural gas properties from unaffiliated third parties, such as our August 2025 acquisition of Sitio.

•High-grade our asset base. We intend to continue to high-grade our asset base and opportunistically divest non-core mineral interests, such as the Non-Permian Divestiture on February 9, 2026, and then redeploy proceeds into our core areas of focus.

•Maintain a conservative capital structure to allow financial flexibility. Since our formation, we have maintained a conservative capital structure that has allowed us to opportunistically purchase accretive mineral and other interests. We are committed to maintaining a conservative leverage profile and will continue to seek to opportunistically fund accretive acquisitions. In addition to returning capital to our stockholders through base and variable dividends in accordance with our dividend policy and share repurchases under our repurchase program, we intend to continue to manage our balance sheet and debt obligations to ensure our ability to successfully operate in challenging business and commodity price environments.

•Hedge to manage commodity price risk and to protect our balance sheet and cash flow. We use a combination of derivative instruments to economically hedge exposure to changes in commodity prices and maintain financial and balance sheet flexibility.

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Competitive Strengths

We believe the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

•Oil rich resource base in one of North America’s leading resource plays. As of December 31, 2025, 244 horizontal drilling rigs were operating in the Permian Basin, representing 46% of the total U.S. onshore horizontal rig activity. The majority of our mineral and royalty acreage is positioned in the core of both the Midland and Delaware Basins in the Permian Basin. Production on our mineral and royalty acreage for the year ended December 31, 2025, and our estimated net proved reserves are heavily oil-weighted.

•Sustainable, high margin business unburdened by capital expenses with minimal operating expenses. Our mineral and royalty interests provide us with cash flows without the requirement to fund drilling and completion costs or lease operating expenses. Our operating margins generate free cash flow growth in a stable or rising price environment as the underlying production associated with our royalty interests continues to grow.

•Experienced and proven management team. Diamondback provides us with personnel and general and administrative services, including the services of the executive officers, senior management and other employees, pursuant to the Services and Secondment Agreement. The members of our executive team have significant industry experience, most of which has been focused on resource play development primarily in the Permian Basin, and Diamondback, which currently operates approximately 35% of our mineral and royalty acreage, has a proven track record of executing on multi-rig development drilling programs and extensive experience primarily in the Permian Basin. In addition, our executive team has significant experience with acquisition of properties and businesses in the oil and natural gas industry. We believe the industry relationships and experience of our management team are essential for the execution of our business strategy.

•Favorable and stable business environment. We primarily focus our growth in the Permian Basin, one of the oldest, most prolific hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks in the Permian Basin as compared to other unconventional hydrocarbon basins. We believe that the impact of the proven application of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities on our mineral and royalty acreage as compared to other unconventional hydrocarbon basins.

•Enhanced Permian Basin footprint facilitating the pursuit of disciplined transactions in highly fragmented minerals market. On August 19, 2025, we completed the Sitio Acquisition, which has significantly expanded our footprint across the core of the Permian Basin and increased our exposure to high quality development activity. We believe that completion and integration of the Sitio Acquisition further enhances our ability to pursue disciplined transactions in what continues to be a highly fragmented minerals market, apply superior land and data capabilities to source and evaluate opportunities and integrate assets efficiently.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

The estimated reserves as of December 31, 2025, 2024 and 2023 are based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. The internal and external technical persons responsible for preparing or auditing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis. The purpose of Ryder Scott’s audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates for 2025, 2024 and 2023. The proved reserve audits performed by Ryder Scott for 2025, 2024 and 2023 covered 100% of our total proved reserves for each respective year. A copy of the summary audit report prepared by Ryder Scott is included as Exhibit 99.1 to this Annual Report.

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Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025, were estimated using a deterministic method.

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (i) performance-based methods, (ii) volumetric-based methods, and (iii) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. In general, our proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods included, but were not limited to, decline curve analysis, which utilized extrapolations of available historical production data. In certain cases where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. All proved undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included, but were not limited to, production data, downhole completion information, geologic data and historical well cost and operating expense data.

The process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates of this report. As a result, our petroleum engineers and geoscience professionals have an internal controls process to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to our assets. Our internal technical staff met with our independent reserve auditors periodically during their audit of the December 31, 2025 reserve report to discuss the assumptions and methods used in our proved reserve estimation process. As part of the audit process, we provide historical information to the independent reserve auditors for our properties such as ownership interest, oil and gas production, commodity prices and operating and development costs. Our Executive Vice President and Chief Engineer is primarily responsible for overseeing the preparation of all of our reserve estimates and overseeing communications with our independent reserve auditor. Our Executive Vice President and Chief Engineer is a petroleum engineer with over 22 years of reservoir and operations experience and our geoscience staff has an average of approximately 17 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, commodity prices and operating and development costs to estimate economic lives of our properties. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2025 and any differences were reviewed with our Executive Vice President and Chief Engineer. For 2025, our reserve auditor’s estimates of our proved reserves did not differ materially from our estimates by more than the established audit tolerance guidelines of ten percent.

The internal control procedures utilized in the preparation of our proved reserve estimates are intended to ensure reliability of reserve estimations, and include, but are not limited to the following:

•review and verification of historical production data, which is based on actual production as reported by our operators;
•preparation of reserve estimates by the primary reserve engineers or under their direct supervision;
•review by the primary reserve engineers of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
•review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
•direct reporting responsibilities by our Executive Vice President and Chief Engineer to our Chief Executive Officer and by the current primary reserve engineer to our President;
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•prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer, Diamondback’s Executive Vice President and Chief Operating Officer, our Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis;
•review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis;
•verification of property ownership by our land department; and
•no employee’s compensation is tied to the amount of reserves booked.

For estimates and further discussion of our proved developed and proved undeveloped reserves, see Note 15—Supplemental Information on Oil and Natural Gas Operations (Unaudited) in Item 8. Financial Statements and Supplementary Data of this report.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

Our properties are located primarily in the Midland and Delaware Basins of the Permian Basin in Texas. At December 31, 2025, 2024 and 2023, the Midland Basin and the Delaware Basin each contained 15% or more of our total proved reserves.

The following table sets forth information regarding our share of our operators’ net production of oil, natural gas and natural gas liquids for these fields along with our share of our operators’ net production from fields containing less than 15% of our total proved reserves:

MidlandDelaware
Other(2)
Total
Production Data:
Year Ended December 31, 2025
Oil (MBbls)14,000 3,579 296 17,875 
Natural gas (MMcf)36,364 13,208 2,104 51,676 
Natural gas liquids (MBbls)5,757 1,243 1,233 8,233 
Combined volumes (MBOE)(1)
25,818 7,023 1,880 34,721 
Year Ended December 31, 2024
Oil (MBbls)7,105 2,766 68 9,939 
Natural gas (MMcf)16,802 7,482 322 24,606 
Natural gas liquids (MBbls)2,976 1,174 31 4,181 
Combined volumes (MBOE)(1)
12,881 5,187 153 18,221 
Year Ended December 31, 2023
Oil (MBbls)5,789 2,210 29 8,028 
Natural gas (MMcf)13,088 5,984 58 19,130 
Natural gas liquids (MBbls)2,323 782 3 3,108 
Combined volumes (MBOE)(1)
10,293 3,989 42 14,324 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Production data includes the Denver-Julesburg, Eagle Ford and Williston basins beginning August 19, 2025, the effective date on which the properties were acquired.

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The following table sets forth certain average sales price information for each of the periods indicated:

Year Ended December 31,
202520242023
Average Sales Prices:
Oil ($/Bbl)$63.27 $75.48 $77.13 
Natural gas ($/Mcf)$1.08 $0.60 $1.62 
Natural gas liquids ($/Bbl)$19.31 $21.17 $21.55 
Combined ($/BOE)$38.77 $46.85 $50.06 
Oil, hedged ($/Bbl)(1)
$62.38 $74.57 $76.05 
Natural gas, hedged ($/Mcf)(1)
$1.92 $0.85 $1.37 
Natural gas liquids ($/Bbl)(1)
$19.31 $21.17 $21.55 
Combined price, hedged ($/BOE)(1)
$39.54 $46.68 $49.13 
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes realized gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.

Productive Wells

As of December 31, 2025, we owned an average 2.2% net revenue interest in 43,355 gross productive wells, including an average 2.2% net revenue interest in 39,434 gross oil productive wells and an average 1.3% net revenue interest in 3,921 gross natural gas productive wells. As of December 31, 2025, we had 14 gross wells with an average 10.1% net revenue interest in process of being drilled by Diamondback. The expected timing of our wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Productive wells consist of producing wells capable of production, including natural gas awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest.

Acreage

The following table sets forth information as of December 31, 2025, relating to the gross and net royalty acreage of our mineral interests:

BasinGross Royalty AcreageNet Royalty Acreage
Delaware1,986,216 36,004 
Midland1,891,742 50,595 
Other584,161 9,404 
Total acreage4,462,119 96,003 

Our net interest in production from our mineral interests is based on lease royalty terms which vary from property to property. Our interest in the majority of these properties is perpetual in nature; however, a portion of our net royalty acreage consists of overriding royalty interests which may be subject to expiration. Net royalty acres are defined as net mineral acres multiplied by the average lease royalty interest and other burdens.

Title to Properties

Prior to the drilling of an oil or natural gas well, it is typical in our industry for the well operator to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability to increase production and reserves in the future. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, our business and cash available for dividends may be adversely affected.

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Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties, mineral interests and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices than operators of our mineral and royalty acreage. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Our ability to acquire additional mineral, royalty, overriding royalty, net profits and similar interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, fuel oils and nuclear energy. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while demand for natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below. For purposes of this section, where applicable, references to “we,” “us,” and “our” refer to Viper Energy, Inc., to the extent the Company were to acquire working interests in the future as well as to any operators of our properties, including our current operators.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Federal and state legislation and regulation affecting the oil and natural gas industry is evolving. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters. Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas; require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits; result in the suspension or revocation of necessary permits, licenses and authorizations; require that additional pollution controls be installed; and impose substantial liabilities for pollution resulting from operations. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and
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regulations occur frequently, and may result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements that could materially and adversely affect our business and prospects. Further, on January 20, 2025, President Trump issued a series of executive orders and memoranda signaling a shift in environmental and energy policy in the United States, including the revocation of several Biden administration-era executive orders related to public health, the environment, climate change and climate-related financial risks. President Trump also declared a “national energy emergency,” directing agencies to expedite conventional energy projects. While the Trump Administration’s changes to the environmental regulatory landscape in the United States continue to develop, it is possible that additional changes in the future could impact our results of operations and those of our customers.

Waste Handling. The Resource Conservation and Recovery Act, or the RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in the U.S. Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any changes in such laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Additionally, emerging contaminants, like per- and polyfluoroalkyl substances (“PFAS”) such as perfluorooctanesulfonic acid and perfluorooctanoic acid compounds, have become subject to CERCLA regulation in addition to existing federal and state chemicals regulation, and PFAS have recently been regulated under the Toxic Substances Control Act (“TSCA”). Other emerging contaminants could also become subject to regulation under CERCLA, TSCA or comparable state laws. Governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial or regulatory compliance obligations upon our operators would not have a material adverse effect on our operations or financial position.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act of 1990, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.

The scope of waters regulated under the CWA has fluctuated in recent years due to notable rulemaking efforts and judicial challenges. On January 18, 2023, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated
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final rules expanding the scope of waters protected under the CWA. However, on May 25, 2023, the United States Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the decision. Later, on March 12, 2025, the EPA issued guidance narrowing the definition of “wetland” from the Biden-era definition in order to align that definition with the Supreme Court’s May 25, 2023 decision. These recent actions have provided some clarity. However, to the extent the EPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the CWA’s jurisdiction, we or third-party operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. On March 12, 2025, the EPA announced that it is re-evaluating the existing regulations on oil and gas wastewater, including exploring opportunities for discharge from centralized wastewater treatment facilities. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the CWA or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

Air Emissions. The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal CAA that establish new emission controls for oil and natural gas production and processing operations, which are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source if they are under common control for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (including carbon dioxide, methane and other gases). Such rules and regulations have been proposed, amended and challenged, and finalized, and compliance deadlines have been extended or regulations rescinded. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022, or the IRA, include billions of dollars in incentives for the development of renewable energy and supporting infrastructure. In March 2024, the EPA published a final rule in the Federal Register to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. On November 26, 2025, the EPA issued an interim final rule to extend certain compliance deadlines from the March 2024 final rule. These incentives and regulations, if implemented, may encourage the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA amends the CAA to impose a “waste emissions charge” on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their greenhouse gas emissions to the EPA,
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including those sources in offshore and onshore petroleum and natural gas production and gathering and boosting source categories. On November 18, 2024, the EPA published a final rule on the methane emissions charge, which became effective on January 17, 2025. Twenty-three states filed a lawsuit challenging the CAA amendment, and the One Big Beautiful Bill Act, passed July 4, 2025, suspends the “waste emissions charge” from future implementation. The current U.S. presidential administration has also expressed an intention to scale back various other climate regulations launched under previous administrations. On February 12, 2026, the EPA issued a final rule eliminating the 2009 greenhouse gas endangerment finding, which underpins U.S. federal regulation of greenhouses gas emissions under the Clean Air Act. The final rule is expected to be subject to extensive litigation and the impact of such scaling back is difficult to predict at this time. Despite this shift, numerous proposals have been and continue to be made at the international, regional and state levels of government that are intended to limit emissions of greenhouse gases by enforceable requirements and voluntary measures.

The EPA has also finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry. On November 26, 2025, the EPA issued an interim final rule to extend certain compliance deadlines from the March 2024 final rule. Additionally, several states have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and natural gas operations. For example, on November 4, 2020, the Texas Railroad Commission adopted new guidance on when flaring is permissible, requiring operators to submit more specific information to justify the need to flare or vent gas.

In addition to domestic regulation of greenhouse gases, there continues to be international interest in a global framework for greenhouse gas reductions. However, on January 20, 2025, President Trump issued an executive order directing the United States Ambassador to the United Nations to immediately withdraw from the Paris Agreement and revoke the U.S. International Climate Finance Plan, and on January 27, 2025, the United States’ Acting Ambassador to the United Nations submitted a notification of withdrawal from the Paris Agreement. The withdrawal became effective on January 27, 2026.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of the U.S. Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

On March 8, 2024, the EPA published a final rule to expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. On December 1, 2025, the EPA published a final rule extending several compliance deadlines in the March 2024 final rule. This final rule was promptly challenged in federal court by environmental groups. While there is uncertainty regarding the scope and extent of EPA’s regulation of air emissions from hydraulic fracturing operations, any future laws and their implementing regulations may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions. Additionally, in the future, the EPA may impose more stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions, which may increase our compliance or operating costs.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of Federal Occupational Safety and Health Act for
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disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits and temporarily suspend operations for waste disposal wells. For example, in September 2021, the Texas Railroad Commission curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has subsequently suspended some permits there and expanded the restrictions to other areas. In addition, the Texas Railroad Commission has imposed monitoring and reporting requirements for any new disposal well permitted in the Permian Basin. These restrictions on the disposal of produced water, a moratorium on new produced water wells, and additional monitoring and reporting requirements could result in increased operating costs, forcing our operators or their vendors to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. Our operators or their vendors may also limit disposal well volumes, disposal rates and pressures or locations, or require them to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business.

On December 17, 2024, the Texas Railroad Commission adopted a significant overhaul of its rules regulating oil and gas waste management facilities in Texas. The new rules went into effect on July 1, 2025. The new rules, found in 16 TAC Chapter 4, cover waste from oil and gas operations, such as rock and other material pulled up from the ground during drilling, as well as waste from other operations. The rules impose requirements related to waste management practices and production methods, such as recycling produced water. The rules also update requirements on the design, construction, operation, monitoring, and closure of waste management units.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Endangered Species. The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species, such as the lesser prairie chicken or dunes sagebrush lizard, are located in areas where our operators or their vendors operate, their operations or any work performed related to their operations could be prohibited or delayed, or expensive mitigation could be required. The designation of previously unprotected species as threatened or endangered in areas where our operators or their vendors operate could result in the imposition of restrictions on our operators’ or their vendors’ operations or any work related to their operations.

Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
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The availability, terms and cost of transportation of oil and natural gas significantly affect its marketability and sale. The interstate transportation and sale for resale of natural gas, and the interstate transportation of oil, is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Oil and natural gas pipelines are also subject to extensive safety regulation by the Pipeline and Hazardous Materials Safety Administration, a part of the U.S. Department of Transportation, and state regulatory agencies. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC regulation of interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas, which is predominantly state-regulated.

Although oil and natural gas prices are currently unregulated, the U.S. Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: the location of wells; the method of drilling and casing wells; the timing of construction or drilling activities, including seasonal wildlife closures; the rates of production or “allowables”; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which they can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure our stockholders that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales. Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Beginning with that legislation in 1978 and continuing with the Wellhead Decontrol Act of 1989, federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties for violations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil (including other liquid hydrocarbons) in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

We do not have any employees. Since the Conversion, our business and affairs are overseen by our board of directors, and Diamondback continues to provide personnel and general and administrative services to us, including the services of the executive officers and other employees, pursuant to the Services and Secondment Agreement. Please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes in Item 8. Financial Statements and Supplementary Data of this report. All of the individuals that conduct our business, including our executive officers, are employed by Diamondback.

Facilities

Our principal executive offices are located in Midland, Texas and are owned by Diamondback. We believe that these facilities are adequate for our current operations.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investors page of our website at www.viperenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.

ITEM 1A. RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of the material risks relating to our business activities. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.

Risks Related to Our Business

Geopolitics and market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth and production.

From the beginning of 2023 through the end of 2025, WTI has ranged from $55.27 to $93.68 per Bbl, and the Henry Hub price of natural gas has ranged from $1.58 to $5.29 per MMBtu. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other
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trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions, and actions taken by OPEC+, continued to contribute to economic and pricing volatility. These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. If the prices of oil and natural gas decline, our operations and financial condition may be materially and adversely affected. Our business may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints in the Permian Basin where we have mineral and royalty interests.

Diamondback and certain of our other operators increased production on our acreage during 2025, but Diamondback continued to exercise capital discipline by using the majority of their excess cash flow for debt repayment and/or return to their stockholders rather than expanding its drilling programs. We cannot reasonably predict whether production levels will remain at current levels or the full extent of the impact of the events above may have on our industry and our business.

Based on the current commodity pricing environment and industry conditions, we recorded non-cash ceiling test impairments of $768 million in 2025. If SEC Prices decline further as compared to commodity prices used in prior periods, we may be required to record additional impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our revolving credit facility, which may be determined at the discretion of our lenders.

Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.

We use commodity price derivatives, which have historically included fixed price swap contracts, fixed price basis swap contracts and costless collar contracts with corresponding put and call options to reduce price volatility associated with certain of our royalty income. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on WTI pricing (WTI Cushing and Argus WTI Midland) and with natural gas derivative settlements based on the Henry Hub and Waha Hub pricing. By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. Our counterparties have been determined to have an acceptable credit risk; therefore, we do not require collateral from our counterparties. By using derivative instruments, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas and natural gas liquids above the price levels of the commodity price derivatives used to manage price risk.

For additional information regarding our use of commodity price derivatives and our outstanding derivative contracts as of December 31, 2025, see Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

The risks relating to the transition to a low carbon economy could impose new costs on our operations that may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have evolving and varied views on climate change matters in recent years. Such views, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in: (i) the enactment of new or evolving climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in battery technology), (iii) variability in demand from consumers and industry for energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles), and (iv) development of, and variable demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, oil and natural gas, which would likely have a material adverse impact on our
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investments. The enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see Items 1 and 2. Business and Properties—Regulation—Climate Change of this report.

In addition to potentially reducing demand for oil and natural gas, and the availability of oilfield services and midstream and downstream customers, further regulatory or other climate change initiatives, to the extent they continue, may create investment and reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. Certain stakeholders and capital providers may seek to restrict or seek to impose more stringent conditions with respect to their investment in or financing of certain carbon intensive sectors, which could result in capital being unavailable to us, or only at a significantly increased cost.

Changing political and social perspectives on climate change and other environmental, social and governance factors may create risks and uncertainties impacting our business.

We may not be able to meet evolving expectations of stakeholders, including governmental officials, standard setters, investors, employees, and customers, relating to climate change, human capital, and other environmental, social and governance (“ESG”) issues. There is conflicting and evolving pressures from proponents and opponents of ESG, and a failure to adapt to changing views could negatively impact our reputation. Proponents and opponents of these issues are increasingly resorting to activism, including litigation, to advance their positions. Such activism also includes attempts to effect changes to public companies’ businesses or governance to deal with climate change-related issues through shareholder proposals, public campaigns, proxy solicitations or other actions. Any such future actions may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, whether due to our activities or the activities of the acquired entities or operations prior to their acquisition by us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages. Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions to our business, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and cash flow.

Increased costs of capital could adversely affect our business.

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

We may not have sufficient available cash to pay any quarterly dividend on our Common Stock, our cash available for dividends may vary significantly from quarter to quarter and our board of directors may in the future modify or revoke our cash dividend policy at any time at its discretion. Our dividend policy could limit our ability to grow and make acquisitions.

We may not have sufficient cash available to pay base or variable dividends to our common stockholders each quarter. Furthermore, our cash dividend policy does not require us to pay dividends on a quarterly basis or otherwise. The amount of cash we have to distribute each quarter principally depends upon the amount of royalty income we generate, which is dependent upon the volumes of production sold and the prices that our operators realize from the sale of such production. In addition, the actual amount of cash we will have to distribute each quarter under our cash dividend policy will be reduced by payments in respect of income taxes, debt service and other contractual obligations and fixed charges, increases in reserves for future operating or capital needs that the board of directors may determine is appropriate, lease bonus income, dividend equivalent rights payments and preferred dividends, if any, and any common share repurchases. The board of directors may further modify or revoke our dividend policy at any time in the future at its discretion. For information regarding our dividend policy and the recent modifications, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report. As a result, quarterly dividends paid to our stockholders may vary significantly from quarter to quarter and may be zero.

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As a result of our cash dividend policy, we have limited cash available to reinvest in our business or to fund acquisitions. We expect that we will continue to fund a portion of our capital expenditures and other needs with borrowings under the revolving credit facility and from the proceeds of debt and equity offerings. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could result in an inability to complete acquisitions or finance the capital expenditures necessary to replace our reserves.

To the extent we issue additional shares in connection with any acquisitions or growth capital expenditures or as in-kind dividends, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level.

We depend on a small number of operators for a substantial portion of the development and production on our mineral and royalty acreage. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of an operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations.

The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Any development and production activities on our properties are subject to our operators’ reasonable discretion. The level, success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including: commodity prices; the timing and amount of capital expenditures by our operators, which could be significantly more than anticipated; the ability of our operators to access capital; the availability, high cost or shortages of rigs and other suitable drilling equipment, raw materials, supplies and oilfield services; the availability of production and transportation infrastructure and qualified operating personnel; regulatory restrictions; the operators’ expertise, operating efficiency and financial resources; approval of other participants in drilling wells; the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; the selection of technology; the selection of counterparties for the sale of production; and the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our royalty income and cash available for dividends to our stockholders. If reductions in production by the operators are implemented on our properties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures by operators than we currently anticipate.

Approximately 22% of our total estimated proved reserves as of December 31, 2025, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators on our mineral and royalty acreage. The reserve data included in our reserve reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill, complete and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

We may not be able to terminate our leases if any of our operators declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

Under many of the leases that cover our mineral and royalty interests, a failure on the part of our operators to make royalty payments to us gives us the right to terminate the applicable lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

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However, many of our mineral and royalty interests are covered by leases that do not provide us with the contractual right to terminate the lease or repossess the property if an operator fails to timely make royalty payments to us. In such instances, we may be forced to resort to litigation to seek payment of past due royalties and statutory interest, without the ability to replace the operator.

The producing properties in which we have mineral and royalty interests are primarily concentrated in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with a single geographic area. In addition, a large amount of our proved reserves is attributable to a small number of producing horizons within this area.

The producing properties in which we have mineral and royalty interests are currently geographically primarily concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints faced by our operators or their customers, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids on our mineral and royalty acreage, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities on our mineral and royalty acreage.

Extreme regional weather events may occur that can affect our operators’ suppliers or customers, which could adversely affect us. Climate changes may also increase the frequency and severity of significant weather events over time. Further, any increase in flaring of natural gas production on our mineral and royalty acreage due to weather-related events, or otherwise, could expose us to reputational risks and adversely impact our or our operators’ contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us. Likewise, a weather event could reduce the availability of electrical power, road accessibility, and transportation facilities, which could have an adverse impact on production volumes on our mineral and royalty acreage (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our mineral and royalty acreage, we could experience any of these conditions at the same time, resulting in a relatively greater impact on us than they might have on other companies that have a more diversified portfolio of assets. Such delays or interruptions could have a material adverse effect on our business, financial condition and cash flow.

In addition to the geographic concentration of our mineral and royalty acreage, as of December 31, 2025, most of our proved reserves are concentrated in the Wolfberry resource play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause our operators to permanently or temporarily shut-in all of the wells on our mineral and royalty acreage.

Our future success depends on the development or acquisition of additional reserves, and our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our results of operations and cash available for dividends.

Our future success depends upon the development or acquisition of additional oil and natural gas reserves that are economically recoverable, as our proved reserves will generally decline as reserves are depleted. To increase reserves and production, we would need to undertake replacement activities or use our operators to undertake development, exploration and other replacement activities, requiring substantial capital expenditures. We may not have sufficient resources to acquire additional reserves and our operators may not have sufficient resources to undertake exploration, development, production or other replacement activities. Such activities by our operators may not result in significant additional reserves and efforts to drill productive wells at low finding costs may be unsuccessful. In addition, we do not expect to retain cash from our operations for replacement capital expenditures. Furthermore, although our revenues and cash available for dividends may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including: recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems including title defects or environmental issues, which, if material, can render an interest worthless, nor will it permit us to become sufficiently familiar with the properties to assess fully their
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deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Environmental or other regulatory issues may arise with respect to acquired entities or operations years after the acquisitions, any of which can adversely affect our results of operations, financial condition and cash available for dividends. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Significant acquisitions and other strategic transactions may involve other risks that may cause our business to be adversely impacted, including diversion of our management’s attention to evaluating and negotiating such transactions and our failure to realize the full benefit that we expect in estimated proved reserves, production volume or other benefits anticipated therefrom, or to realize these benefits within the expected time frame.

We may not be able to complete acquisitions or do so on commercially acceptable terms, as our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, our future acquisitions may be in geographic regions in which we do not currently hold properties. If we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements and other unforeseen difficulties. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations, the process of which may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. Any of the unfavorable circumstances mentioned above could have a material adverse effect on our financial condition, results of operations and cash available for dividends. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash available for dividends.

We may not realize the anticipated benefits from our acquisitions, including the Sitio Acquisition and the 2025 Drop Down.

We have recently completed several significant acquisitions, including the Sitio Acquisition and the 2025 Drop Down, and expect to pursue additional acquisitions as part of our growth strategy. Realizing anticipated benefits from these acquisitions depends in part on integrating acquired assets efficiently and effectively, which we may not accomplish due to, among other things:

•challenges associated with operating a larger organization and managing geographically dispersed assets;
•the difficulty of integrating corporate, technological and administrative functions and complex systems, technology and networks, and addressing inconsistencies in standards, controls, operational philosophies and corporate cultures;
•diversion of attention and resources from regular business operations;
•increasing our indebtedness and the complexity of our capital structure;
•incurring environmental or regulatory liabilities and encountering title defects;
•disruptions in relationships with operators, customers, suppliers, landowners and other business partners;
•challenges in hiring, training, retaining or integrating qualified personnel;
•assuming unknown or contingent liabilities and incurring unforeseen expenses; and
•inaccuracies in assumptions regarding estimated proved reserves, future production, prices, revenues and costs.

If we are unable to effectively manage the integration of our current or future acquisitions, or if our business activities are interrupted as a result, our business, results of operations and financial condition could be adversely affected.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed are on our property and do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for dividends may be materially affected.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate
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recoveries and operating and development costs, if any. As a result, estimated quantities of proved reserves and projections of future production rates may be incorrect. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices and production levels may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A portion of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

We are dependent on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.

We are dependent on electric power, internet and telecommunication infrastructure and Diamondback’s information systems and computer based programs. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively conduct our business will be limited and any such consequence could have a material adverse effect on our business.

Rapid growth in artificial intelligence (“AI”) related data centers and other high‑intensity computing is materially increasing regional electricity demand and straining grids, which—together with extreme weather conditions, intermittent renewable generation, and other market constraints—can reduce power availability, increase prices (including scarcity pricing), and cause outages. Reduced power reliability could disrupt our operators’ drilling, completion, and production activities; impair midstream operations; hinder remote monitoring and data integrity; and force suspensions or shutdowns or unplanned spending on backup power and communications, any of which could have a material adverse effect on our business and results of operations.

We are subject to cybersecurity and data privacy risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

We rely extensively on Diamondback’s information technology systems and infrastructure, including but not limited to data hosting platforms, real-time data acquisition systems, internally developed and third-party software, cloud services and other internally or externally hosted hardware and software platforms (collectively, “IT Systems”) for operational and other purposes, such as to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, and (iii) communicate with our management and board of directors, as well as, our vendors, suppliers and other third parties. Diamondback owns and manages certain IT Systems but also relies on third parties for a range of IT Systems and other products or services. Diamondback and certain third-party providers also collect, maintain and/or process proprietary data about our business, such as trade secrets, as well as personally identifiable information about our employees, business partners and others (collectively, “Confidential Information”).

We regularly experience attempted cyberattacks and other incidents, including phishing attacks and attacks on certain of our third-party providers, and we expect future cyberattacks and incidents to occur in varying degrees. To date, no incidents have materially affected our company, including our business strategy, results of operations or financial condition, but we cannot guarantee that material incidents will not occur in the future.

Diamondback’s IT Systems and our Confidential Information, and those of our vendors, service providers and other third-party providers and business partners, are vulnerable to evolving cybersecurity threats, including, without limitation, denial-of-service attacks; malicious software (e.g., ransomware); the exploitation of known and unknown misconfigurations, “bugs,” and other hardware or software vulnerabilities; data privacy breaches by insiders or others with authorized access; social engineering (e.g., phishing) attacks; attempts to gain unauthorized access to our data and Diamondback’s systems; and other electronic or physical security breaches. More recently, advancements in AI pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition or screening questions to confirm identities. In addition, generative AI systems are increasingly used by malicious actors to create more sophisticated cyber-attacks (i.e., more realistic phishing or other attacks) and to circumvent controls, evade detection and even remove forensic evidence, rendering incident detection and remediation more challenging. These and other threat-related advancements expose us and Diamondback to increasing costs, including costs associated with additional personnel, protection technologies and policies and procedures and third-party experts and consultants. There can be no assurance that Diamondback’s cybersecurity risk management program, including its controls or processes, will be fully implemented,
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complied with or effective in protecting IT Systems and Confidential Information. Moreover, neither we nor Diamondback manage the security controls or processes deployed by our third-party providers, such as cloud services that support our operations, and therefore, successful cyberattacks that disrupt or result in unauthorized access to third-party IT Systems could materially impact our and Diamondback’s operations and financial results. Similarly, we have acquired and continue to acquire companies that may have cybersecurity vulnerabilities or unsophisticated measures, which exposes us to significant risk. A significant cybersecurity attack or incident could compromise our Confidential Information or disrupt our operations, normal business functions and other aspects of our business.

Diamondback provides personnel and general and administrative services to us, including personnel and infrastructure that underlie our cybersecurity risk management program. As cyber incidents continue to evolve, Diamondback may be required to expend additional resources (for which we may be partially responsible) to continue to modify or enhance protective measures or to investigate and remediate any vulnerability to cyber incidents. Diamondback maintains specialized insurance for possible liability resulting from a cyberattack on its assets; however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that Diamondback will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and cash flows. See Item 1C. Cybersecurity below for additional information.

A variety of U.S. federal, state and international laws and regulations govern the collection, use, retention, sharing and security of personal data. All 50 states have enacted legislation on data breach notification requirements and many states continue to enact laws on matters of privacy, data protection and cybersecurity. The existing privacy-related laws and regulations are evolving and subject to potentially differing interpretations. In addition, various U.S. federal, state and foreign legislative and regulatory bodies continue to enact new laws regarding privacy and data protection, as well as expand the scope of existing laws. We cannot predict the impact of any such evolving privacy-related laws on our business, results of operations or financial condition, but may find it necessary to enhance the existing systems and procedures, which may involve substantial expense or distraction from other aspects of our business. In addition, any violations of applicable privacy-related laws or regulations may require us to address legal claims, sustain monetary penalties or incur other liabilities, as well as cause reputational damage, any of which could adversely impact our business, results of operations or financial condition.

Risks Related to Our Indebtedness

Our substantial indebtedness could adversely affect our results of operations, business flexibility and our ability to service our debt.

We have incurred a substantial amount of debt to finance our recent acquisitions and for other corporate purposes. Our ability to make scheduled payments of principal, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. We are dependent on cash flow generated by the Operating Company to repay the Guaranteed Senior Notes. The Operating Company’s business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If the Operating Company is unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional capital on terms that may be onerous or highly dilutive. However, we cannot assure you that alternative financing plans would be consummated on desirable terms or would be adequate to meet any debt service obligations then due.

Our revolving credit facility and the indentures governing the Guaranteed Senior Notes outstanding contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create additional liens; sell or transfer assets; merge or consolidate with another entity; pay or declare dividends; designate certain of our subsidiaries as unrestricted subsidiaries; create unrestricted subsidiaries; and engage in transactions with affiliates.

In addition, the revolving credit facility requires us to maintain a certain net debt to capitalization ratio. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these restrictive covenants could result in default under the revolving credit facility. If a default occurs, the lenders under the revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which
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would result in an event of default under the indentures governing the Guaranteed Senior Notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under the revolving credit facility and the Guaranteed Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Additionally, any significant reduction in the borrowing base under our revolving credit facility as a result of borrowing base redeterminations, following a decline in commodity prices or otherwise, may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operations and cash flow. Further, if the outstanding borrowings under the revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of the borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Lastly, our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate tied to SOFR. SOFR tends to fluctuate based on multiple factors, including general short-term interest rates, rates set by the U.S. Federal Reserve, and other central banks and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Risks Inherent in an Investment in Us

Diamondback controls us and its interests may conflict with ours or yours in the future.

Diamondback beneficially owns approximately 42.1% of the voting power of our capital stock, on a fully diluted basis. For so long as Diamondback continues to have voting power over a significant percentage of our capital stock, even at times when such amount is less than 50%, it will be able to significantly influence the composition of our board of directors and the approval of actions requiring stockholder approval. Although the holders of our Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the General Corporation Law of the State of Delaware (the “DGCL”), including the election of our board of directors, pursuant to our certificate of incorporation, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of our outstanding Common Stock (i) Diamondback has the right to designate up to three persons to serve as members of our board of directors, and (ii) our board of directors may not appoint any person other than a Diamondback seconded employee as an executive officer of our company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned), or (y) the affirmative vote of the holders of at least 80% of the voting power of our capital stock. Currently, there are two Diamondback designees to our board of directors—Travis Stice and Kaes Van’t Hof. Pursuant to the Services and Secondment Agreement, Diamondback continues to provide personnel and general and administrative services to us and OpCo, including the services of the executive officers and other employees. Accordingly, Diamondback will have significant influence with respect to our board of directors, management, business plans and policies, including the appointment and removal of our officers. In particular, for so long as Diamondback continues to beneficially own a significant percentage of our capital stock, it will be able to cause or prevent a change of control of our company or a change in the composition of our board of directors and could preclude any unsolicited acquisition of our company. The concentration of ownership could deprive you of an opportunity to receive a premium for your shares of Common Stock as part of a sale of our company and ultimately might affect the market price of our Common Stock.

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We do not have any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and certain of its affiliates, and thus are not solely focused on our business.

We do not have any employees and we rely solely on Diamondback to provide us with personnel and general and administrative services, including the services of the executive officers, senior management and other employees, under the terms and conditions of the Services and Secondment Agreement. Because Diamondback provides services to us that are similar to those it performs for itself and its affiliates, it may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it were solely focused on our business and operations. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself or others in providing its services. If Diamondback does not devote sufficient attention to the management and operation of our business or otherwise breaches the provisions of the services and secondment agreement, our financial results may suffer and our ability to pay dividends to our stockholders may be reduced. Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of the executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

The market price of our shares of Class A Common Stock could be adversely affected by sales of substantial amounts of our Class A Common Stock in the public or private markets.

We have provided registration rights to Diamondback and other parties collectively owning a substantial portion of our outstanding shares of Class A Common Stock on an as-converted basis. Pursuant to these registration rights, we have registered, under the Securities Act, all of the Class A Common Stock owned by Diamondback and those other parties for resale (including Class A Common Stock issuable in respect of the Class B Common Stock under the related exchange agreement or under the exchange provisions of the Operating Company’s limited liability company agreement). Sales by holders of a substantial number of our Class A Common Stock in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A Common Stock or could impair our ability to obtain capital through an offering of equity securities.

U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

In 2022, the IRA enacted a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting more than $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. If we are or become subject to CAMT including as a result of our affiliation with Diamondback, our cash tax obligations for U.S. federal income taxes could be significantly accelerated.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law. Among other provisions, the OBBB provides for immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the CAMT, and enhancements to limits on business interest expense deductions. The OBBB also imposes limits on deductibility of charitable contributions by corporations. To the extent the timing or amount of our tax deductions are affected by the applicable provisions of the OBBB, our cash tax obligations may be impacted.

The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue additional guidance on how the CAMT and other provisions of the IRA and OBBB will be applied or otherwise administered,
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and such guidance may differ from our interpretations. We continue to evaluate the IRA and OBBB and their effect on our financial results and operating cash flow.

The provision of our certificate of incorporation requiring exclusive venue in the Court of Chancery in the State of Delaware for certain types of lawsuits may have the effect of discouraging lawsuits against us and our directors, officers and stockholders.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware generally shall be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, employee or stockholder of the Company to the Company or its stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or bylaws or (iv) any other action asserting a claim against the Company governed by the internal affairs doctrine. This choice of forum provision does not waive our compliance with our obligations under the federal securities laws and the rules and regulations thereunder. Moreover, the provision does not apply to suits brought to enforce a duty or liability created by the Exchange Act or by the Securities Act.

This choice of forum provision may increase costs to bring a claim, discourage claims or limit a stockholder’s ability to bring a claim in a judicial forum that the stockholder finds favorable for disputes with the Company or our directors, officers or employees, which may discourage such lawsuits against the Company and its directors, officers and employees, even though an action, if successful, might benefit our stockholders. Alternatively, if a court were to find the choice of forum provision to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such matters in other jurisdictions, which could increase our costs of litigation and adversely affect our business and financial condition.

Our certificate of incorporation does not limit the ability of Diamondback and certain of its directors, principals, officers, employees and their respective affiliates to compete with us.

Our certificate of incorporation provides that none of Diamondback, any of its directors, principals, officers, employees or respective affiliates will have any duty to refrain from engaging, directly or indirectly, in the same business activities or similar business activities or lines of business in which we operate. In the ordinary course of their business activities, these persons may engage in activities where their interests conflict with our interests or those of our other stockholders.

These persons also may pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, these persons may have an interest in our pursuing acquisitions, divestitures and other transactions that, in their judgment, could enhance their investment, even though such transactions might involve risks to our common stockholders.

Anti-takeover provisions in our organizational documents and Delaware law might discourage or delay acquisition attempts for us that you might consider favorable.

Our certificate of incorporation and bylaws contain provisions that may make the merger or acquisition of our company more difficult without the approval of our board of directors. Among other things, these provisions would allow us to authorize the issuance of shares of one or more series of preferred stock, including in connection with a stockholder rights plan, financing transactions or otherwise, the terms of which series may be established and the shares of which may be issued without stockholder approval, and which may include super voting, special approval, dividend, or other rights or preferences superior to the rights of the holders of Common Stock; prohibit stockholder action by written consent unless such action is consented to by the board of directors; provide for certain limitations on convening special stockholder meetings; provide (i) that the board of directors is expressly authorized to make, alter, or repeal our bylaws, and (ii) that our stockholders may only amend our bylaws with the approval of at least a majority of all of the outstanding shares of our capital stock entitled to vote; and establish advance notice requirements for nominations for elections to our board or for proposing matters that can be acted upon by stockholders at stockholder meetings.

These anti-takeover provisions could discourage, delay or prevent a transaction involving a change in control of our company, including actions that our stockholders may deem advantageous, or could negatively affect the trading price of our Common Stock. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

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Our ability to pay base and variable dividends to the holders of our Class A Common Stock or make repurchases under our repurchase program may be limited by requirements under our certificate of incorporation, our holding company structure, applicable provisions of Delaware law and contractual restrictions.

Under our current dividend policy, we pay quarterly base plus variable cash dividends on our Class A Common Stock. The outstanding shares of Class B Common Stock are entitled to an aggregate quarterly preferred dividend of $20,000 in cash. Other than the insignificant preferred dividend requirement, we are not required to pay dividends to our stockholders on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of our board of directors, which may change our dividend policy at any time. Our ability to pay cash dividends to holders of our Class A Common Stock depends on a number of factors, including among other things, general economic and business conditions, our strategic plans and prospects, our businesses and investment opportunities, our financial condition and operating results, capital requirements and other anticipated cash needs, contractual restrictions and obligations, legal, tax and regulatory restrictions and other factors.

Additionally, as a holding company, our ability to pay dividends or repurchase shares of our Common Stock or OpCo Units is subject to the ability of OpCo and any future subsidiaries to provide cash to us. Viper Energy, Inc. has no material assets other than its membership interest in OpCo, which along with OpCo’s subsidiaries, holds all of the mineral and royalty interests and other assets consolidated on our balance sheet.

Under the DGCL we may only pay dividends to our stockholders out of (i) our surplus, as defined and computed under the provisions of the DGCL, or (ii) our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. If we do not have sufficient surplus or net profits, we will be prohibited by law from paying any such dividend. In addition, the terms of our revolving credit facility include, and any other debt instruments or financing arrangements may from time to time include covenants or other restrictions that could constrain our ability to pay dividends, make other distributions or repurchase shares of our Common Stock or OpCo Units. Our certificate of incorporation contains provisions authorizing us to issue series of preferred stock that may have designations, preferences, rights, powers and duties that are different from, and may be senior to, those applicable to our Class A Common Stock.

For additional information regarding stockholders’ equity and our repurchase program, see Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity Risk Management Strategy

Diamondback provides us with personnel and general and administrative services pursuant to the Services and Secondment Agreement, including the personnel and infrastructure that underlie our cybersecurity risk management program. In connection therewith, Diamondback has implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect Diamondback’s systems, identify and remediate on a regular basis vulnerabilities in Diamondback’s systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. Diamondback has also engaged third-party consultants to conduct penetration testing and risk assessments. Diamondback’s cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.

Diamondback’s cybersecurity risk management program is integrated into its overall enterprise risk management program, which integrates our enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas that apply to us.

Diamondback’s cybersecurity risk management program, which it provides to us under the Services and Secondment Agreement, includes:

•risk assessments designed to help identify material cybersecurity risks to critical systems, information, products, services, and the broader enterprise IT and operational technology (“OT”) environments;
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•a security team principally responsible for managing (i) cybersecurity risk assessment processes, (ii) security controls, and (iii) its response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of its security controls;
•security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity;
•cybersecurity awareness training of its employees, including incident response personnel and senior management, including those who provide these services for us;
•cybersecurity tabletop exercises for members of its cybersecurity incident response team and legal department;
•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and
•a third-party risk management process for service providers, which may include diligence, assessments and/or contractual requirements, depending on each service provider’s operational criticality and relative risk profile.

Cybersecurity Governance

Diamondback’s cybersecurity governance program is led by its Senior Vice President and Chief Information Officer, with support from the internal information technology department. Diamondback’s Senior Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. Diamondback’s Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, Diamondback’s cybersecurity incident response team is responsible for responding to cybersecurity incidents and is guided by its Computer Security Incident Response Plan. Progress and developments in Diamondback’s cybersecurity governance program are communicated to members of its and our executive team. Diamondback’s and our management takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by Diamondback; alerts and reports produced by security tools deployed in the enterprise IT and OT environments; and through reporting by employees and service providers. While our board of directors is ultimately responsible for enterprise-wide risk oversight, the board’s committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. In particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in the risk management strategy and continues to be an area of increasing focus for our board, the audit committee and management.

The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program. Board members also receive presentations on cybersecurity topics from Diamondback’s Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Diamondback’s cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors.

Risks from identified cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A. Risk Factors of this report for additional information regarding cybersecurity risks we face and their potentially material impact on our business strategy, results of operations and financial condition.

ITEM 3. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Listing and Holders of Record

Shares of our Class A Common Stock are listed on Nasdaq under the symbol “VNOM.” There were 63 holders of record of our Class A Common Stock on February 20, 2026. There is no trading market for our Class B Common Stock; however, shares of our Class B Common Stock or the TWR Class B Option (as defined in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), together with an equal number of OpCo Units, are exchangeable for the same number of shares of our Class A Common Stock at the discretion of the holders under the terms and conditions of OpCo’s limited liability company agreement or the applicable exchange agreement with such holders. There were 31 holders of record of our Class B Common Stock on February 20, 2026.

Dividend Policy

Under our current dividend policy, we intend to pay a base dividend, as well as a variable dividend that takes into account capital returned to stockholders via our repurchase program. We currently intend to pay quarterly variable dividends of at least 75% of our available cash less the base dividend declared and the amount paid for repurchases of our Common Stock and OpCo Units as part of our repurchase program for the applicable quarter.

Our available cash and the available cash of the Operating Company for each quarter is determined by our board of directors following the end of such quarter. We expect that our available cash will generally equal the Adjusted EBITDA attributable to us for the applicable quarter, less cash needed for income taxes payable, debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that our board of directors deems necessary or appropriate, lease bonus income (net of applicable taxes), and other insignificant expenses including dividend equivalent rights payments and preferred distributions.

The percentage of cash available for distribution by the Operating Company to us pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen our balance sheet while also expanding the return of capital program through our repurchase program.

We are also required to pay a quarterly preferred dividend in respect of our Class B Common Stock in the aggregate amount of $20,000 per quarter. Other than the preferred dividend requirement, we are not required to pay dividends to our stockholders on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of our board of directors.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

Our Class A Common Stock repurchase activity for the three months ended December 31, 2025, was as follows:

Period
Total Number of Shares Purchased(1)
Average Price Paid Per Share(2)
Total Number of Shares Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(1)(3)
(In millions, except per share amounts and shares in ones)
October 1, 2025 - October 31, 2025861,825$37.34 860,087$302 
November 1, 2025 - November 30, 2025466,757$36.97 466,757$284 
December 1, 2025 - December 31, 202575,905$38.72 75,905$241 
Total1,404,487$37.29 1,402,749
(1)Includes 1,738 shares of Class A Common Stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase. On December 10, 2025 our board of directors approved expanding the repurchase program to include repurchases of OpCo Units and shares of Class B
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Common Stock. The OpCo Units and the Company’s Class B Common Stock are not registered securities pursuant to Section 12 of the Exchange Act and as such repurchases of such unregistered securities are excluded from the shares listed in the table above. During December 2025, the Company, in a privately negotiated transaction, repurchased 1,000,000 OpCo Units for an aggregate purchase price of approximately $41 million, or $40.65 per OpCo Unit, and cancellation of an equal number of shares of the Company’s Class B Common Stock. The approximately $241 million remaining under the repurchase program for future repurchases at December 31, 2025 in the table above gives effect to such repurchase of OpCo Units.
(2)The average price paid per share includes any commissions paid to repurchase stock.
(3)On July 26, 2022, our board of directors increased the authorization under our then-in-effect repurchase program from $250 million to $750 million and on February 18, 2026 further increased the authorization to $1.75 billion. This repurchase program has no expiration date and remains subject to market conditions, applicable legal requirements, contractual obligations and other factors and may be suspended, modified or extended, from time to time, or may be discontinued at any time, in each case, by our board of directors.

Stock Performance Graph

The following performance graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate such information by reference into such a filing. The performance graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.

The performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP. The graph assumes an investment of $100 on December 31, 2020, and that all dividends were reinvested.
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As of December 31,
Calculated Values202020212022202320242025
Viper Energy, Inc.$100.00$194.07$314.02$328.99$544.01$454.07
S&P 500$100.00$128.68$105.36$133.03$166.28$195.98
XOP$100.00$166.76$242.36$250.96$248.37$243.04

ITEM 6. [RESERVED]
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in Item 8. Financial Statements and Supplementary Data of this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this report.

Overview

We are a publicly traded Delaware corporation focused on owning and acquiring mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment.

The following discussion includes a comparison of our results of operations, including changes in our operating income, and liquidity and capital resources for fiscal year 2025 and fiscal year 2024. A discussion of changes in our results of operations from fiscal year 2024 compared to fiscal year 2023 has been omitted from this report, but may be found in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 26, 2025, and is incorporated by reference in this report from such prior Annual Report on Form 10-K.

Recent Developments

2026 Activity

Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under our existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax.

Cash Dividends

On February 18, 2026, our board of directors approved (i) an increase to our annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025, and (ii) a combined quarterly base and variable cash dividend of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit payable on March 12, 2026.

Divestiture of Non-Permian Assets

On February 9, 2026, we completed the Non-Permian Divestiture for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the Non-Permian Divestiture were used to repay the Term Loan (as defined below) and to reduce borrowings outstanding on the 2025 Revolving Credit Facility (as defined below).

2025 Activity

Acquisitions Update

Sitio Acquisition

On August 19, 2025, we completed the Sitio Acquisition in an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

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2025 Drop Down

On May 1, 2025, we completed the 2025 Drop Down for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of our Class B Common Stock (collectively, the “Drop Down Equity Issuance”). The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback.

Other Acquisitions

During the year ended December 31, 2025, we acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $140 million, including customary closing adjustments. Additionally, during the year ended December 31, 2025, we acquired from Morita Ranches Minerals, LLC, mineral and royalty interests representing 1,691 net royalty acres in the Permian Basin for consideration consisting of $208 million in cash and 2,400,297 OpCo Units together with an equal number of shares of our Class B Common Stock, including customary transaction costs and post-closing adjustments.

At December 31, 2025, our footprint of mineral and royalty interests totaled approximately 96,003 net royalty acres, approximately 35% of which are operated by Diamondback.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further information.

Debt Transactions

Notes Offering and Retirement of Notes

On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion. Using approximately $824 million of the net proceeds from the issuance of the Guaranteed Senior Notes, we redeemed all of our 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”) and on November 1, 2025 we redeemed our 5.375% Senior Notes due 2027 (the “2027 Notes”), including accrued and unpaid interest through the date of redemption and any redemption premiums. We used the remaining net proceeds to partially retire Sitio’s net debt of approximately $1.2 billion including any fees, costs and expenses related to the redemption or repayment of such debt, and for general corporate purposes.

Additionally, in the second quarter of 2025, prior to redemption, we opportunistically repurchased principal amounts of $50 million of the 2027 Notes in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which is now the issuer with respect to the Guaranteed Senior Notes.

Term Loan

On July 23, 2025, Former Viper, as guarantor, the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, entered into a $500 million term loan credit agreement (the “Term Loan”), which was fully drawn to partially fund the retirement of Sitio’s net debt. Following the closing of the Sitio Acquisition, New Viper became an additional guarantor of the borrower’s obligations under the Term Loan. Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent providing for a senior unsecured revolving credit facility with a commitment amount of $1.5 billion (the “2025 Revolving Credit Facility”). The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the Operating Company, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced
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the borrower’s previous revolving credit facility, and will mature on June 12, 2030, unless extended in accordance with its terms. Following the OpCo Conversion, Viper LP became the borrower under the 2025 Revolving Credit Facility.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt.

2025 Equity Offering

On February 3, 2025, we completed an underwritten public offering of 28,336,000 shares of our Class A Common Stock, which included 3,696,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $44.50 per share, for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to fund (i) a portion of the cash consideration for the 2025 Drop Down, (ii) the cash consideration for various individually insignificant acquisitions, and (iii) for general corporate purposes.

Commodity Prices and Certain Other Market Considerations

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. OPEC+ continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels and can heavily influence volatility in oil prices. During 2025, 2024 and 2023, WTI prices averaged $64.73, $75.76 and $77.60 per Bbl, respectively, and Henry Hub prices averaged $3.62, $2.41 and $2.66 per MMBtu, respectively. For additional information around risks related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Based on 2025 commodity prices, industry conditions and the results of the quarterly ceiling tests, we were required to record aggregate non-cash impairments of $768 million on our proved oil and natural gas interests during the year ended December 31, 2025. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.

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Production and Operational Update

As of December 31, 2025, there were 98 gross rigs operating on our mineral and royalty acreage, eight of which are operated by Diamondback. During 2025, we completed the Sitio Acquisition and the 2025 Drop Down, which reinforced the durability of our growth outlook and leveraged our leading position in the minerals and royalty sector to advance our differentiated acquisition strategy. Currently, we estimate full year production levels in 2026 to range between approximately 120 MBOE/d to 132 MBOE/d.

The following table summarizes our gross well information excluding the recently divested non-Permian assets as of December 31, 2025, unless otherwise specified:

Diamondback OperatedThird-Party OperatedTotal
Horizontal wells turned to production (fourth quarter 2025)(1):
Gross wells107632739
Net 100% royalty interest wells5.37.713.0
Average percent net royalty interest5.0 %1.2 %1.8 %
Horizontal wells turned to production (year ended December 31, 2025)(2):
Gross wells4151,6702,085
Net 100% royalty interest wells20.721.342.0
Average percent net royalty interest5.0 %1.3 %2.0 %
Horizontal producing well count:
Gross wells4,09219,94224,034
Net 100% royalty interest wells258.3311.1569.4
Average percent net royalty interest6.3 %1.6 %2.4 %
Horizontal active development well count(3):
Gross wells2631,1251,388
Net 100% royalty interest wells20.917.338.2
Average percent net royalty interest7.9 %1.5 %2.8 %
Line of sight wells(4):
Gross wells3041,0661,370
Net 100% royalty interest wells16.915.132.0
Average percent net royalty interest5.6 %1.4 %2.3 %
(1)Average lateral length of 11,283 feet.
(2)Average lateral length of 11,618 feet.
(3)The total 1,388 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.
(4)The total 1,370 line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our net royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Results of Operations

The following table summarizes our income and expenses for the periods indicated:

Year Ended December 31,
20252024
(In millions)
Operating income:
Oil income$1,131 $750 
Natural gas income56 15 
Natural gas liquids income159 89 
Royalty income1,346 854 
Lease bonus income24 6 
Lease bonus income—related party24 — 
Other operating income1 1 
Total operating income1,395 861 
Costs and expenses:
Production and ad valorem taxes94 61 
Depletion607 214 
Impairment768 — 
General and administrative expenses18 8 
General and administrative expenses—related party17 11 
Other operating expenses31 — 
Total costs and expenses1,535 294 
Income (loss) from operations(140)567 
Other income (expense):
Interest expense, net(96)(74)
Gain (loss) on derivative instruments, net44 11 
Gain (loss) on early extinguishment of debt(32)— 
Other income (expense), net(1)— 
Total other income (expense), net(85)(63)
Income (loss) before income taxes(225)504 
Provision for (benefit from) income taxes(19)(100)
Net income (loss)(206)604 
Net income (loss) attributable to non-controlling interest(138)245 
Net income (loss) attributable to Viper Energy, Inc.$(68)$359 

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:

Year Ended December 31,
20252024
Production data:
Oil (MBbls)17,875 9,939 
Natural gas (MMcf)51,676 24,606 
Natural gas liquids (MBbls)8,233 4,181 
Combined volumes (MBOE)(1)
34,721 18,221 
Average daily oil volumes (BO/d)48,973 27,156 
Average daily combined volumes (BOE/d)95,126 49,784 
Average sales prices:
Oil ($/Bbl)$63.27 $75.48 
Natural gas ($/Mcf)$1.08 $0.60 
Natural gas liquids ($/Bbl)$19.31 $21.17 
Combined ($/BOE)(2)
$38.77 $46.85 
Oil, hedged ($/Bbl)(3)
$62.38 $74.57 
Natural gas, hedged ($/Mcf)(3)
$1.92 $0.85 
Natural gas liquids ($/Bbl)(3)
$19.31 $21.17 
Combined price, hedged ($/BOE)(3)
$39.54 $46.68 
Average costs ($/BOE):
Production and ad valorem taxes$2.71 $3.34 
General and administrative - cash component0.81 0.86 
Total operating expense - cash$3.52 $4.20 
General and administrative - non-cash stock compensation expense$0.20 $0.16 
Interest expense, net$2.76 $4.05 
Depletion$17.48 $11.77 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Realized price net of all deducts for gathering, transportation and processing.
(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.

Significant changes in our revenues and expenses for 2025 compared to the same period in 2024 are discussed below.

Royalty Income. Our royalty income is a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes.

Royalty income increased $492 million in 2025 compared to the same period in 2024. This net increase consisted of an additional $701 million in royalty income from the 91% growth in production, partially offset by a net decrease of $209 million due primarily to lower average prices received for our oil and natural gas liquids production during 2025 compared to the same period in 2024.

Of the 91% growth in production, approximately 46% is attributable to the 2025 Drop Down and 32% is attributable to the Sitio Acquisition. The remainder of the growth is primarily from new wells added between periods and other individually insignificant acquisitions. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our acquisitions.
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Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated:

Year Ended December 31,
20252024
Amount
(In millions)		Per BOEPercentage of Royalty IncomeAmount
(In millions)		Per BOEPercentage of Royalty Income
Production taxes$69 $1.99 5.1 %$43 $2.33 5.0 %
Ad valorem taxes25 0.72 1.9 18 1.01 2.1 
Total production and ad valorem taxes$94 $2.71 7.0 %$61 $3.34 7.1 %

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Production taxes and ad valorem taxes as a percentage of royalty income in 2025 were relatively consistent with the same period in 2024.

Depletion. The increase in depletion expense of $393 million in 2025 compared to the same period in 2024 consisted primarily of (i) $198 million due to an increase in the depletion rate to $17.48 per BOE in 2025, resulting primarily from the addition of leasehold costs and reserves from acquisitions completed in 2025, compared to $11.77 per BOE for the same period in 2024, and (ii) $195 million from growth in production volumes.

Impairment. In 2025, we recorded non-cash ceiling test impairment charges of $768 million due to the carrying value of our proved reserves exceeding their estimated future net cash flows utilizing the SEC’s methodology and pricing at December 31, 2025. The excess value resulted primarily from recording properties acquired in the 2025 Drop Down at Diamondback’s historical carrying value, which exceeded the value calculated in the third and fourth quarter 2025 ceiling tests, due primarily to declining SEC Prices. No impairment expense was recorded in 2024.

Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Given the overall decline in SEC Prices from the first quarter of 2025 through the first two months of 2026, we believe an additional material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026; however, based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026.

General and Administrative Expenses. The following table shows a breakout of our general and administrative expenses for the periods presented:

Year Ended December 31,
20252024
(In millions, except per BOE amounts in ones)
General and administrative expenses$18 $8 
General and administrative expenses—related party17 11 
General and administrative expenses$35 $19 
General and administrative expenses (per BOE)$1.01 $1.02 

Interest Expense, Net. The increase in net interest expense of $22 million in 2025 compared to the same period in 2024 consisted primarily of (i) $40 million in additional expense on our Guaranteed Senior Notes, which were issued July 23, 2025, (ii) $11 million in additional interest expense incurred on the Term Loan, and (iii) other individually insignificant changes. These increases in net interest expense were partially offset by (i) interest cost savings of approximately $16 million due to the early termination of the Notes, (ii) $8 million in additional interest income, and (iii) a decrease of approximately $5
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million in interest expense on our current and previous revolving credit facility due to lower average borrowings outstanding in 2025.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:

Year Ended December 31,
20252024
(In millions)
Gain (loss) on derivative instruments, net
$44 $11 
Net cash receipts (payments) on derivatives
$30 $(3)

The $33 million increase in the gain on derivative instruments, net in 2025 compared to the same period in 2024 consists primarily of (i) an $11 million net gain on our natural gas contracts, which consists of a $30 million net increase in cash receipts on our settled natural gas basis swaps, partially offset by a $19 million decrease in the value of our open natural gas contracts primarily due to changes in the differential between prices for Waha Hub and Henry Hub, (ii) a $13 million decrease in the estimated fair value of our 2026 WTI Contingent Liability based on fluctuations in the final WTI 2025 Average price (each as defined in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), and (iii) other individually insignificant changes. See Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our open contracts at December 31, 2025.

Gain (Loss) on Early Extinguishment of Debt. The $32 million loss on early extinguishment of debt in 2025 is due to the retirement of the 2031 Notes. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt at December 31, 2025.

Provision for (Benefit from) Income Taxes. The $81 million decrease in income tax benefit in 2025 compared to the same period in 2024 primarily resulted from recognizing a pre-tax loss attributable to Viper in 2025 compared to pre-tax income attributable to Viper in 2024, driven by the $768 million non-cash ceiling test impairments recorded in 2025. Additionally, the income tax benefit recognized in 2024 reflects the full release of a valuation allowance of $156 million during the fourth quarter of 2024. See Note 9—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of income tax expense.

Net Income (Loss) Attributable to Non-Controlling Interest. The change to $138 million in net loss attributable to non-controlling interest in 2025 from $245 million in net income attributable to non-controlling interest in 2024 is primarily due to the non-cash ceiling test impairments recorded in 2025 and changes in the non-controlling interest in the Operating Company resulting from (i) the Drop Down Equity Issuance, (ii) the issuance of OpCo Units to fund the Sitio Acquisition, and (iii) the issuance of OpCo Units to Tumbleweed Royalty IV, LLC in the fourth quarter of 2024, which were partially offset by a dilution of the non-controlling interest following the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report) and the 2025 Equity Offering.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flow from operations, equity and debt offerings, borrowings under our revolving credit facility, term loan agreement and proceeds from sales of non-core assets. Our primary uses of cash have been dividends to our stockholders, Operating Company distributions to the holders of OpCo Units, repayments of debt, capital expenditures for the acquisition of our mineral and royalty interests in oil and natural gas properties, including the recently completed Sitio Acquisition, the 2025 Drop Down, and various individually insignificant acquisitions and repurchases of our Common Stock and OpCo Units. At December 31, 2025, we had approximately $1.4 billion of liquidity consisting of $13 million in cash and cash equivalents and $1.4 billion in available borrowings under the 2025 Revolving Credit Facility. See further discussion of changes in our sources of cash in “—Capital Resources” below.

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Our working capital requirements are supported by our cash and cash equivalents and the 2025 Revolving Credit Facility. We may draw on the 2025 Revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including dividends, debt service obligations, repayment of debt maturities, any repurchases of our Common Stock, OpCo Units or Guaranteed Senior Notes and any amounts that may ultimately be paid in connection with contingencies.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

Continued prolonged volatility in the capital, financial and/or credit markets due to changing or adverse macroeconomic conditions, including tariffs, higher interest rates, global supply chain disruptions, actions taken by OPEC members and other exporting nations and geopolitical global conflicts may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

Cash Flows

The following table presents our cash flows for the period indicated:

Year Ended December 31,
20252024
(In millions)
Net cash provided by (used in) operating activities$1,053 $620 
Net cash provided by (used in) investing activities(2,424)(608)
Net cash provided by (used in) financing activities1,357 (11)
Net increase (decrease) in cash and cash equivalents$(14)$1 

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volumes of oil and natural gas sold by our operators. The increase in net cash provided by operating activities in 2025, compared to the same period in 2024 was primarily driven by an increase in royalty and lease bonus income and receiving cash payments on our derivatives in 2025 compared to making cash payments to counterparties in 2024. These increases in cash flow were partially offset by an increase in certain cash costs for production and ad valorem taxes, general and administrative expenses, other operating expenses which include severance costs related to the Sitio Acquisition and other changes in our working capital accounts including the timing of when accounts receivable are collected and accounts payable are remitted. See “—Results of Operations” above for further discussion of significant changes in our income and expenses.

Investing Activities

Net cash used in investing activities during the year ended December 31, 2025, was primarily related to acquisitions of oil and natural gas interests, including the approximately $1.2 billion repayment made for Sitio’s outstanding debt as part of the consideration for the Sitio Acquisition, the 2025 Drop Down, and acquisitions of oil and natural gas interests from other third parties. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for additional information on these acquisitions.

Net cash used in investing activities during the year ended December 31, 2024, primarily related to acquisitions of oil and natural gas interests from third parties, which includes $654 million in cash paid for the Tumbleweed Acquisitions (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), partially offset by proceeds of $88 million primarily from the divestiture of non-Permian oil and natural gas interests.

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Financing Activities

Net cash provided by financing activities during the year ended December 31, 2025, was primarily attributable to (i) net proceeds from the issuance of the Guaranteed Senior Notes of $1.6 billion, (ii) proceeds of $1.2 billion from the 2025 Equity Offering, and (iii) net proceeds from the Term Loan of $500 million. These cash inflows were partially offset by (i) $745 million of dividends paid to holders of our OpCo Units and our Class A Common Stock, (ii) $430 million paid for the retirement of the outstanding principal on our 2027 Notes, (iii) $427 million paid for the retirement of the outstanding principal and the redemption premium on our 2031 Notes, (iv) $194 million of securities repurchases under the Company’s repurchase program, and (v) repayments net of borrowings of $156 million on the 2025 Revolving Credit Facility.

Net cash used in financing activities during the year ended December 31, 2024, was primarily attributable to $481 million of dividends paid to stockholders and the Operating Company’s unitholders, which was largely offset by proceeds of $476 million from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report).

Capital Resources

The 2025 Revolving Credit Facility and Other Debt Instruments

At December 31, 2025, our credit facility, which matures on June 12, 2030, had a commitment amount of $1.5 billion, with $105 million in outstanding borrowings and $1.4 billion of availability. In the first quarter of 2026, we fully repaid the $105 million of outstanding borrowings under our credit facility.

Additionally, at December 31, 2025, we had $500 million in outstanding borrowings under the Term Loan, which we subsequently repaid in full with proceeds from the Non-Permian Divestiture in February 2026.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our outstanding debt at December 31, 2025.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S., which impact the interest rates we receive on our variable rate debt and interest rate swaps. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. In May 2025, Fitch Investor Services upgraded our credit rating to investment grade, the second such investment grade credit rating for us. This upgrade granted us access to a broader investor base, lower interest rates and reduced collateral requirements; therefore, enhancing our liquidity. Currently, our credit ratings from the three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB-);
•Fitch Investor Services (BBB-); and
•Moody’s Investor Services (Ba1).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

Guaranteed Senior Notes

At December 31, 2025, we had total principal payments due on our outstanding Guaranteed Senior Notes of $500 million in 2030 and $1.1 billion in 2035. Additionally, we have a remaining aggregate interest expense obligation of $750 million on the Guaranteed Senior Notes with $87 million due in 2026, an aggregate of $174 million due for years 2027 to 2028, an aggregate of $174 million due for years 2029 to 2030, and $315 million due thereafter. The Guaranteed Senior Notes are not subject to any mandatory redemption or sinking fund requirements. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for further information on the Notes.

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Repurchases of Securities

On December 10, 2025, our board of directors expanded our repurchase program to include repurchases of our Class B Common Stock and OpCo Units in addition to our previously authorized Class A Common Stock. On February 18, 2026, our board of directors also approved an increase in our repurchase program authorization from $750 million to $1.75 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA. Since the inception of our repurchase program through February 20, 2026, we have repurchased an aggregate of 18,878,469 shares of our Common Stock and OpCo Units for a total cost of $525 million, excluding any applicable excise tax, leaving approximately $1.2 billion for future repurchases under the repurchase program. See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program.

Cash Dividends and Return of Capital Update

We paid a total of $745 million and $481 million in dividends, on our Class A Common Stock, OpCo Units and participating securities under the LTIP during 2025 and 2024, respectively.

Because of our high operating and free cash flow margin, strong balance sheet, and the Non-Permian Divestiture closure, we returned 90% of cash available for distribution to stockholders with respect to the fourth quarter of 2025. As a result, in addition to repurchases under our repurchase program, we will pay a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case payable on March 12, 2026, to eligible holders of record at the close of business on March 5, 2026. The dividend to stockholders consists of a base quarterly dividend of $0.38 per share of Class A Common Stock and a variable quarterly dividend of $0.14 per share of Class A Common Stock.

We moved closer to our net debt target of $1.5 billion following the closure of the Non-Permian Divestiture on February 9, 2026, and are positioned to increase our return of capital upwards of 100% of future cash available for distribution to stockholders, while also delivering sustainable per-share growth.

See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program and dividends. We expect to continue paying quarterly cash dividends in respect of our common shares. Future base and variable dividends are not required and are at the discretion of the board of directors, who may change the dividend policies at any time.

Supplemental Guarantor Disclosure

On July 9, 2025, New Viper, Former Viper and the Operating Company filed a registration statement on Form S-3 with the SEC registering debt securities of the Operating Company. On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion, which are fully and unconditionally guaranteed by each of Former Viper and New Viper. Following the OpCo Conversion, Viper LP became the issuer of the Guaranteed Senior Notes.

The Guaranteed Senior Notes and the guarantees are the issuer’s and each guarantor’s respective senior unsecured obligations and rank equally in right of payment with all of the issuer’s and each guarantor’s respective existing and future senior indebtedness, including all of the issuer’s and each guarantor’s obligations under the 2025 Revolving Credit Facility and the New Loan, and senior in right of payment to any of the issuer’s and each guarantor’s future indebtedness that is expressly subordinated in right of payment to the Guaranteed Senior Notes and the guarantees, respectively.

The Guaranteed Senior Notes and the guarantees are effectively subordinated to any of the issuer’s and each guarantor’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and are structurally subordinated to all of the existing and future indebtedness and other liabilities (including trade payables) of each of the issuer’s and each guarantor’s respective subsidiaries that is not an obligor on the Guaranteed Senior Notes.

In the event of bankruptcy, liquidation, reorganization or other winding up of the issuer or a guarantor or upon a default in payment with respect to, or the acceleration of, any senior secured indebtedness of the issuer or a guarantor, the assets of the issuer or such guarantor that secure such senior secured indebtedness will be available to pay obligations on the Guaranteed Senior Notes and the guarantees only after all obligations under such senior secured indebtedness have been repaid in full from such assets. There may not be sufficient assets remaining to pay amounts due on any or all of the Guaranteed Senior Notes then outstanding and the guarantees.

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The obligations of the guarantors under the guarantees are limited in a manner designed to prevent the guarantees from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. If a guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including contingent liabilities) of such guarantor, and, depending on the amount of such indebtedness, the guarantor’s liability on such guarantee could be reduced to zero.

In accordance with Rule 3-10 of Regulation S-X, subsidiary issuers of obligations guaranteed by the parent are not required to provide separate financial statements, provided that the subsidiary obligor is consolidated into the parent company’s consolidated financial statements, the parent guarantee is “full and unconditional,” except that such guarantee will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, and, subject to certain exceptions, the alternative disclosures specified in Rule 13-01 are provided, which include narrative disclosure and summarized financial information. Accordingly, separate consolidated financial statements of the issuer have not been presented. Furthermore, as permitted under Rule 13-01(a)(4)(vi) of Regulation S-X, we have excluded the summarized financial information for the issuer because the assets, liabilities and results of operations of the issuer are not materially different than the corresponding amounts in our consolidated financial statements and management believes such summarized financial information would be repetitive and would not provide incremental value to investors.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Royalty Income and Revenue Recognition

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales from third-party operators other than Diamondback may not be received for 30 to 90 days after the date production is delivered. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded based upon our royalty interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the operator. We have existing internal controls for our royalty income estimation process and related accruals, but actual third-party royalty income in future periods could differ materially from estimated amounts. At December 31, 2025, our accrual for third-party royalty income was approximately $95 million. Actual revenues received during 2025 for prior years’ production from third parties were not materially different than the amount accrued at December 31, 2024.

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Oil and Natural Gas Accounting and Reserves

We account for oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.

Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future depletion of capitalized costs and result in impairment of assets that may be material. Aggregate non-cash ceiling test impairments of $768 million were recorded on our proved oil and natural gas properties during the year ended December 31, 2025. No impairments were recorded on our proved oil and natural gas properties during the years ended December 31, 2024 and 2023. Based on SEC Prices for oil and natural gas throughout 2025 and into 2026, we believe an additional impairment is reasonably likely to occur in the first quarter of 2026. Any future impairment could be material to our consolidated financial statements.

Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) at least annually for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: (i) monitoring information available from third-party operators of our acreage for future drilling plans, (ii) the success of operators drilling on our acreage, (iii) the assignment of proved reserves, and (iv) current market prices for mineral acreage within our primary basins. At December 31, 2025, our unevaluated properties totaled $4.9 billion. We did not record any impairment on our unevaluated properties during the year ended December 31, 2025, but any such future impairment could be material to our consolidated financial statements.

Acquisitions of Mineral and Royalty Interests

Acquisitions of mineral and royalty interests from third parties are accounted for as asset acquisitions, whereby the purchase price and associated transaction costs are typically capitalized and allocated to the acquired mineral and royalty interests. The allocation is determined based on whether the interests acquired relate to proved or unproved oil and natural gas properties, utilizing the estimated fair value of proved reserves as of the date of acquisition. The valuation of proved reserves for acquisitions from unrelated parties is based on a projection of future cash flows using objective future pricing assumptions and a discount rate consistent with our estimated cost of capital at the time of the acquisition.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to us. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. Estimating future taxable income requires numerous judgments and
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assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas liquids, the expected timing and quantity of future production volumes, and the impact of our commodity derivative instruments on our income. These assumptions are discussed further in the critical accounting estimates titled “— Royalty Income and Revenue Recognition” and “— Oil and Natural Gas Accounting and Reserves.” Due to the impact these various assumptions and estimates can have on our estimates of taxable income, an estimate of the sensitivity to changes is not practicable.

In 2025, management’s assessment of all available evidence, both positive and negative, supporting realizability of our deferred tax assets as required by applicable accounting standards, supported the conclusion that our deferred tax assets are more likely than not to be realized. A variety of positive evidence was assessed. In recent years, we have sustained cumulative pre-tax income due in part to higher commodity prices resulting from strong and stable market conditions, and the locations in which we operate have experienced a sustained and increasing pattern of development by a wide variety of operators, consistent with a presumption of more readily predictable development patterns for our properties. The significant acquisitions completed by us, including the Sitio Acquisition and the 2025 Drop Down, provide additional production capacity to generate future taxable income for utilization of our deferred tax assets. In addition, the recently closed Non-Permian Divestiture provides positive evidence supporting realizability of our capital loss carryforward against the estimated capital gain to be recognized in 2026. Based on these factors, we determined that no valuation allowance on our deferred tax assets is required as of December 31, 2025. As of December 31, 2025, we had net deferred tax assets of $33 million.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for discussion of recent accounting pronouncements and a full listing of our significant accounting policies.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized prices are driven primarily by the prevailing worldwide price for crude oil and prices for natural gas in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable and the prices that our operators receive for production depend on many factors outside of our or their control, as discussed in Item 1A. Risk Factors of this report. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We historically have used fixed price swap contracts, fixed price basis swap contracts, deferred premium put contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data of this report.

At December 31, 2025, we had a net asset derivative position related to our commodity price derivative contracts of $21 million. Utilizing actual derivative contractual volumes under our contracts as of December 31, 2025, a 10% increase in forward curves associated with the underlying commodity would have increased the net asset position by $5 million to approximately $26 million, and a 10% decrease in forward curves associated with the underlying commodity would have
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increased the net asset position by $2 million to approximately $23 million. However, any cash derivative gain or loss may be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas properties and receivables with a limited number of several significant operators who sell our production to numerous purchasers. For the years ended December 31, 2025 and 2024, two operators each accounted for more than 10% of our income, respectively. For the year ended December 31, 2023, one operator accounted for more than 10% of our income. See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for further details. Each of our operators sell to multiple purchasers. We do not require collateral and the failure or inability of our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Volatility in the commodity pricing environment and macroeconomic conditions may enhance the credit risk from our operators and purchasers.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the 2025 Revolving Credit Facility and the Term Loan.

The terms of the 2025 Revolving Credit Facility provide for interest on borrowings at a floating rate equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case, plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate loans and from 1.125% to 2.000% per annum in the case of term SOFR loans, in each case, based on the pricing level. Further, the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitment, based on the pricing level. The pricing level depends on the rating of our long-term senior unsecured debt by certain rating agencies. As of December 31, 2025, we had $105 million in outstanding borrowings under the 2025 Revolving Credit Facility with a weighted average interest rate of 6.02% during the year ended December 31, 2025.

Borrowings under the Term Loan bear interest at a per annum rate elected by us that is equal to SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies. In addition, the fee on undrawn commitments is equal to 0.20% per annum on the aggregate principal amount of such commitments. As of December 31, 2025, we had $500 million in outstanding borrowings under the Term Loan with a weighted average interest rate on borrowings of 5.72% for the year ended December 31, 2025.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

(a)Documents included in this report:
1. Financial Statements
2. Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Viper Energy, Inc.

Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Viper Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of operations, cash flows, and stockholders’ equity for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 25, 2026 expressed an unqualified opinion.

Basis for opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of proved reserves as it relates to the calculation and recognition of depletion and impairment expense and the valuation of acquired reserves in connection with the mineral and royalty interests acquired in the Sitio Acquisition

As described further in Note 2 to the consolidated financial statements, the Company accounts for its oil and natural gas properties using the full cost method of accounting, which requires management to make estimates of proved reserve volumes and future revenues to calculate depletion and impairment expense. Additionally, as described further in Note 4 to the consolidated financial statements, the Company acquired significant mineral and royalty interests through the Sitio Acquisition which requires management to make estimates of reserve volumes and future revenues to value the properties. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the timing and volumetric amounts of production and corresponding decline rate of producing properties associated with the operator’s development plan. In addition, the estimation of reserves is impacted by management’s judgments and estimates regarding the financial performance of wells to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions. For acquired reserves, management utilizes an estimated fair value pricing model in determining the corresponding value of reserves. We identified the estimation of reserves attributable to oil and natural gas interests, including acquired reserves in the Sitio Acquisition, due to its impact on depletion and impairment expense and acquisition accounting, as a critical audit matter.

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The principal considerations for our determination that the estimation of proved reserves is a critical audit matter are that changes in certain inputs and assumptions, which include a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves, could have a significant impact on the measurement of depletion and impairment expense and the fair value of acquired proved oil and natural gas interests. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of reserves included the following, among others.

•We tested the design and operating effectiveness of key controls relating to management’s estimation of proved reserves for the purpose of calculating depletion and impairment expense and management’s estimation of the fair value of the acquired oil and natural gas interests in the Sitio Acquisition.

•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and independent petroleum engineering specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s reserve volumes, and read the year-end reserve report audited by the independent petroleum engineering specialists.

•Identified inputs and assumptions that were significant to the period end determination of proved reserve volumes and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Compared the pricing used in the reserve report to relevant pricing benchmarks and realized prices related to revenue transactions recorded in the current year;

◦Vouched, on a sample basis, the net revenue interests used in the reserve report to underlying land and division order records;

◦Assessed forecasted production estimates by (i) comparing prior year forecasted production amounts to current year actual results and (ii) comparing forecasted production amounts in the current year reserve report to the actual historical production amounts in the current year, in total and for a sample of individual wells;

◦We obtained the Company's assessment of operators’ development plans for proved undeveloped properties reflected in the reserve report and evaluated it against the Company’s historical conversion rates to evaluate the likelihood of development related to the proved undeveloped properties; and

◦Applied analytical procedures on inputs to the reserve report by comparing to historical actual results and to the prior year reserve report.

•Identified inputs and assumptions that were significant to the estimated fair value of the acquired oil and natural gas interests in the Sitio Acquisition and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Evaluated the appropriateness of fair value pricing, including pricing differentials, used in the fair value reserve report by comparing the pricing forecast to observable pricing information as of the acquisition closing date and pricing differentials to actual historical realized pricing of the acquired properties;

◦Evaluated the level of knowledge, skill and ability of the specialist utilized by the Company to assist in the preparation of the estimates of fair value of oil and natural gas properties acquired;

◦Utilized a valuation specialist to evaluate the reasonableness of the Company’s valuation methodology of the Sitio Acquisition, including testing key inputs and assumptions by understanding and assessing the process used to develop the estimate or through development of an independent expectation;

◦Evaluated the appropriateness of the discount rate used in the fair value reserve report of proved reserves by comparing to the Company’s actual weighted average cost of capital;

◦Compared, on a sample basis, the net revenue interest used in the fair value reserve report to the historical reserve report;

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◦Assessed forecasted production estimates in the fair value reserve report for reasonableness by comparing forecasted production amounts to the actual historical production amounts and to the forecasted production in the year-end reserve report for a sample of individual wells;

◦Applied analytical procedures on the fair value reserve report’s forecasted production by comparing to the prior year reserve report’s forecasted production and to the year-end reserve report’s forecasted production of the acquired proved properties; and

◦Compared the unproved acreage value allocated to other recent acquisitions in the same or similar locations.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2013.

Oklahoma City, Oklahoma
February 25, 2026
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Viper Energy, Inc.
Consolidated Statements of Operations

Year Ended December 31,
202520242023
(In millions, except per share amounts, shares in thousands)
Operating income:
Oil income$1,131 $750 $619 
Natural gas income56 15 31 
Natural gas liquids income159 89 67 
Royalty income1,346 854 717 
Lease bonus income24 6 2 
Lease bonus income—related party24 — 108 
Other operating income1 1 1 
Total operating income1,395 861 828 
Costs and expenses:
Production and ad valorem taxes94 61 50 
Depletion607 214 146 
Impairment768 — — 
General and administrative expenses18 8 7 
General and administrative expenses—related party17 11 4 
Other operating expenses31 — 1 
Total costs and expenses1,535 294 208 
Income (loss) from operations(140)567 620 
Other income (expense):
Interest expense, net(96)(74)(47)
Gain (loss) on derivative instruments, net44 11 (26)
Gain (loss) on early extinguishment of debt(32)— — 
Other income (expense), net(1)— — 
Total other income (expense), net(85)(63)(73)
Income (loss) before income taxes(225)504 547 
Provision for (benefit from) income taxes(19)(100)46 
Net income (loss)(206)604 501 
Net income (loss) attributable to non-controlling interest(138)245 301 
Net income (loss) attributable to Viper Energy, Inc.$(68)$359 $200 
Net income (loss) attributable to common shares:
Basic$(0.48)$3.82 $2.69 
Diluted$(0.48)$3.82 $2.69 
Weighted average number of common shares outstanding:
Basic142,53093,93274,176
Diluted142,53093,93274,176






See accompanying notes to consolidated financial statements.
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Viper Energy, Inc.
Consolidated Balance Sheets
December 31,
20252024
(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents$13 $27 
Royalty income receivable (net of allowance for credit losses)262 149 
Royalty income receivable—related party88 31 
Prepaid expenses and other current assets50 31 
Total current assets413 238 
Property:
Oil and natural gas properties:
Proved properties9,746 3,533 
Unproved properties
4,910 2,180 
Other property, equipment and land8 6 
Accumulated depletion and impairment(2,455)(1,081)
Property, net12,209 4,638 
Deferred income taxes (net of allowances)33 185 
Other assets16 8 
Total assets$12,671 $5,069 
Liabilities and Stockholders’ Equity
Current liabilities:
Accrued liabilities$107 $43 
Other current liabilities
4 6 
Total current liabilities111 49 
Long-term debt, net2,186 1,083 
Other long-term liabilities11 30 
Total liabilities2,308 1,162 
Commitments and contingencies (Note 12)
Stockholders’ equity:
Class A Common Stock, $0.000001 par value: 1,000,000,000 shares authorized; 170,942,687 and 102,977,142 shares issued and outstanding as of December 31, 2025, and December 31, 2024, respectively
— — 
Class B Common Stock, $0.000001 par value: 1,000,000,000 shares authorized; 187,023,698 and 85,431,453 shares issued and outstanding as of December 31, 2025, and December 31, 2024, respectively
— — 
Additional paid-in capital4,726 1,569 
Retained earnings (accumulated deficit)(278)118 
Total Viper Energy, Inc. stockholders’ equity4,448 1,687 
Non-controlling interest5,915 2,220 
Total equity10,363 3,907 
Total liabilities and stockholders’ equity$12,671 $5,069 



See accompanying notes to consolidated financial statements.
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Viper Energy, Inc.
Consolidated Statements of Cash Flows


Year Ended December 31,
202520242023
(In millions)
Cash flows from operating activities:
Net income (loss)$(206)$604 $501 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes(83)(149)(7)
Depletion607 214 146 
Impairment768 — — 
(Gain) loss on derivative instruments, net(44)(11)26 
Net cash receipts (payments) on derivatives30 (3)(13)
(Gain) loss on extinguishment of debt32 — — 
Other13 6 3 
Changes in operating assets and liabilities:
Royalty income receivable(25)(13)(27)
Royalty income receivable—related party(34)(28)3 
Accounts payable and accrued liabilities(19)7 6 
Accounts payable—related party(2)1 1 
Other16 (8)(1)
Net cash provided by (used in) operating activities1,053 620 638 
Cash flows from investing activities:
Acquisitions of oil and natural gas interests(1,549)(696)(830)
Acquisitions of oil and natural gas interests—related party(875)— (75)
Proceeds from sale of oil and natural gas interests— 88 (3)
Net cash provided by (used in) investing activities(2,424)(608)(908)
Cash flows from financing activities:
Proceeds from debt3,250 842 973 
Repayments of debt
(2,163)(844)(462)
Net proceeds from public offering1,232 476 — 
Proceeds from public offering to Diamondback— — 200 
Repurchases of shares of Class A Common Stock as part of the repurchase program(153)— (95)
Repurchases of OpCo Units as part of the repurchase program
(41)— — 
Dividends to stockholders(328)(219)(129)
Dividends to Diamondback (361)(255)(196)
Dividends to other non-controlling interest(56)(7)— 
Other(23)(4)(13)
Net cash provided by (used in) financing activities1,357 (11)278 
Net increase (decrease) in cash and cash equivalents(14)1 8 
Cash and cash equivalents at beginning of period27 26 18 
Cash and cash equivalents at end of period
$13 $27 $26 
Supplemental disclosure of cash flow information:
Interest paid$(70)$(74)$(40)
Cash paid for income taxes, net of refunds:
Federal
$(47)$(53)$(50)
State
$(2)$(3)$(1)
Supplemental disclosure of non—cash transactions:
Class A Common Stock issued for acquisition$(1,435)$— $(255)
OpCo Units issued for acquisitions$(1,445)$(468)$— 
OpCo Units issued to related party$(3,599)$— $— 


See accompanying notes to consolidated financial statements.
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Viper Energy, Inc.
Consolidated Statements of Stockholders’ Equity
GeneralAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling Interest
Limited Partners
Partner
Common Stock(1)
Common Units
AmountClass B
Units		AmountAmountClass A
Shares		Class B
Shares
Total
Balance at December 31, 202273,230 $689 90,710 $1 $1 — — $— $— $1,631 $2,322 
Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock
(78,126)(937)(90,710)(1)— 78,126 90,710 938 — — — 
Liquidation of General Partner— — — — (1)— — (1)— — (2)
Common shares/units issued for acquisition— — — — — 9,018 — 255 — — 255 
Common shares/units issued to related party7,215 200 — — — — — — — — 200 
Equity-based compensation— 1 — — — — — — — — 1 
Vesting of restricted stock shares/units73 — — — — — — — — — — 
Dividends/distributions to shareholders— (84)— — — — — — (45)— (129)
Dividends/distributions to Diamondback— (1)— — — — — — (4)(191)(196)
Change in ownership of consolidated subsidiaries, net— 31 — — — — — (133)— 102 — 
Repurchases as part of share/unit buyback(2,392)(67)— — — (1,000)— (28)— — (95)
Net income (loss)— 168 — — — — — — 32 301 501 
Balance at December 31, 2023— $— — $— $— 86,144 90,710 $1,031 $(17)$1,843 $2,857 
(1)The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero at December 31, 2023.



3





















See accompanying notes to consolidated financial statements.
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Viper Energy, Inc.
Consolidated Statements of Stockholders’ Equity - (Continued)
Common Stock(1)
Additional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling Interest
Class A
Shares		Class B
Shares
Total
(In millions, shares in thousands)
Balance at December 31, 202386,144 90,710 $1,031 $(17)$1,843 $2,857 
Common shares issued for acquisition5,279 (5,279)— — — — 
OpCo Units issued for acquisition— — — — 468 468 
Common shares issued to related party11,500 — 476 — — 476 
Equity-based compensation— — 3 — — 3 
Issuance of shares upon vesting of equity awards54 — — — — — 
Dividends to stockholders— — — (219)— (219)
Dividends to Diamondback— — — (5)(250)(255)
Dividends to other non-controlling interest— — — — (7)(7)
Change in ownership of consolidated subsidiaries, net— — 59 — (79)(20)
Net income (loss)— — — 359 245 604 
Balance at December 31, 2024102,977 85,431 1,569 118 2,220 3,907 
Common shares issued for acquisitions
38,536 38,020 1,435 — — 1,435 
Common shares issued to related party— 69,627 — — — — 
OpCo Units issued for acquisition— — — — 1,445 1,445 
OpCo Units issued to related party— — — — 3,599 3,599 
Net proceeds from the issuance of Common Stock28,336 — 1,232 — — 1,232 
Repurchases of shares of Class A Common Stock under repurchase program
(4,016)— (153)— — (153)
Repurchases of OpCo Units and cancellation of Class B Common Stock under repurchase program
— (1,000)— — (41)(41)
Conversion of Class B Common Stock to Class A Common Stock5,054 (5,054)188 — (188)— 
Dividends to stockholders— — — (327)— (327)
Dividends to Diamondback— — — — (361)(361)
Dividends to other non-controlling interest— — — — (56)(56)
Dividend equivalent rights payments
— — — (1)— (1)
Equity-based compensation— — 7 — — 7 
Issuance of shares upon vesting of equity awards56 — — — — — 
Change in ownership of consolidated subsidiaries, net— — 448 — (565)(117)
Net income (loss)— — — (68)(138)(206)
Balance at December 31, 2025170,943 187,024 $4,726 $(278)$5,915 $10,363 
(1)The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero during the periods presented.

See accompanying notes to consolidated financial statements.
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Viper Energy, Inc.
Notes to Consolidated Financial Statements

1.    ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy, Inc. is a publicly traded Delaware corporation. Viper (as defined below) and its consolidated subsidiaries are focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin.

On August 19, 2025, upon completion of the Sitio Acquisition (as defined and discussed in Note 4—Acquisitions and Divestitures), VNOM Sub, Inc. (formerly known as Viper Energy Inc., “Former Viper”) became a wholly owned subsidiary of Viper Energy, Inc. (formerly known as New Cobra Pubco, Inc., “New Viper”), as a result of a merger contemplated by the documents governing the Sitio Acquisition (such merger, the “Viper PubCo Merger”).

Upon completion of the Viper PubCo Merger, each share of Former Viper’s Class A common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger (other than certain excluded shares) was canceled and automatically converted into one share of New Viper Class A common stock, par value $0.000001 per share (“New Viper Class A Common Stock”), and each share of Former Viper’s Class B common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger was automatically canceled and converted into one share of New Viper’s Class B common stock, par value $0.000001 per share (“New Viper Class B Common Stock”).

On December 23, 2025, the Company completed an internal reorganization (the “Reorganization”), pursuant to which, among other things, each outstanding OpCo Unit of Viper Energy Partners LLC, a Delaware limited liability company and Viper’s operating subsidiary (“Old OpCo”), was converted into an equivalent OpCo Unit issued by a newly-formed subsidiary of Viper, VNOM Holding Company LLC (“New OpCo”).

As of December 31, 2025, Viper, through its subsidiaries, owned approximately 46.5% of the outstanding OpCo Units and was the managing member of New OpCo.

Prior to March 8, 2024, the Company was a “controlled company” under the rules of the Nasdaq Stock Market LLC (the “Nasdaq Rules”). On March 8, 2024, the Company’s parent, Diamondback (as defined below), completed an underwritten public offering in which it sold 13,225,000 shares of the Company’s Class A Common Stock (the “Diamondback Offering”). Following the Diamondback Offering, Diamondback’s beneficial ownership was reduced to less than 50% of the Company’s total Common Stock outstanding. As such, the Company ceased to be a “controlled company” under the Nasdaq Rules. Prior to the Diamondback Offering, the Company’s board of directors had a majority of independent directors and a standing audit committee comprised of all independent directors, but had elected to take advantage of certain exemptions from corporate governance requirements applicable to controlled companies under the Nasdaq Rules and, until March 8, 2024, did not have a compensation committee or a committee of independent directors that selects director nominees.

Effective as of March 8, 2024, the Company’s board of directors formed (i) the compensation committee for purposes of making certain executive and other compensation decisions, and (ii) the nominating and corporate governance committee for purposes of making certain nominating and corporate governance decisions, with each such committee’s rights and obligations being subject to the terms and conditions of (x) the Company’s certificate of incorporation, (y) such committee’s charter as adopted by the board, and (z) the services and secondment agreement, dated as of November 2, 2023, pursuant to which Diamondback provides personnel and general and administrative services to the Company, including the services of the executive officers and other employees (the “Services and Secondment Agreement”).

Subsequent transactions completed in 2025 have resulted in Diamondback temporarily owning more than or less than 50% of the Company’s Common Stock causing changes in the Company’s status as a “controlled company” under the applicable Nasdaq Rules. While the controlled company exemptions were at times again available to the Company, the Company’s board of directors did not avail itself of these exemptions. As of December 31, 2025, Diamondback beneficially owned approximately 42.1% of the outstanding voting power of the Company’s Common Stock, on a fully diluted basis after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4—Acquisitions and Divestitures).

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Conversion into Corporation

Effective November 13, 2023, (the “Effective Time”), Viper Energy Partners LP converted from a publicly traded Delaware limited partnership to a Delaware corporation pursuant to a plan of conversion and changed its name from Viper Energy Partners LP to Viper Energy, Inc. Additionally, the certificate of incorporation and the bylaws of Viper Energy, Inc. became effective on the same date. This report includes the results for the Partnership prior to the Conversion and the Company following the Conversion. There are no tax impacts resulting from the Conversion as the Partnership was treated as a corporation for tax purposes.

At the Effective Time, (i) each common unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A Common Stock, (ii) each Class B unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B Common Stock, and (iii) the general partner interest issued and outstanding immediately prior to the Effective Time (100% owned by the General Partner) was cancelled.

At the Effective Time, the Company’s certificate of incorporation and bylaws generally provided its stockholders with substantially the same or greater rights and substantially the same or lesser obligations, as those that limited partners had in the Partnership Agreement. Previously, limited partners were not generally entitled to vote with respect to governance of the Partnership, except for those few matters set forth in the Partnership Agreement. Following the Conversion, except as otherwise expressly provided in the Company’s certificate of incorporation, the holders of Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the General Corporation Law of the State of Delaware, including the election of the board of directors of the Company.

Diamondback continues to provide personnel and general and administrative services to the Company, including the services of the executive officers and other employees, pursuant to the Services and Secondment Agreement. In addition, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of the outstanding Common Stock of the Company, (i) Diamondback will have the right to designate up to three persons to serve as directors of the Company, and (ii) the board of directors of the Company may not appoint any person other than a Diamondback seconded employee as an executive officer of the Company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned), or (y) the affirmative vote of the holders of at least 80% of the voting power of the capital stock of the Company. Currently, there are two Diamondback designees to the board of directors of the Company—Travis Stice and Kaes Van’t Hof.

References in the accompanying consolidated financial statements and related notes thereto to “Viper” refer to (A) New Viper following the Viper PubCo Merger, (B) Former Viper prior to the Viper PubCo Merger, but after the Conversion, and (C) Viper Energy Partners LP prior to the Conversion. References to the “Company,” “our company,” “we,” “our,” “us” or like terms refer collectively to Viper and its consolidated subsidiaries. References to “shares” or per share amounts prior to the Conversion refer to common units and Class B units or per unit amounts of Viper Energy Partners LP. References to shares or per share amounts following the Conversion refer to (A) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of New Viper following the Viper PubCo Merger and (B) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of Former Viper prior to the Viper PubCo Merger.

References to the “Operating Company” or “OpCo” refer to (A) New OpCo following the Reorganization and (B) Old OpCo prior to the Reorganization. References to “OpCo Units” are to the units representing limited liability company interests in the Operating Company.

References to “Diamondback” refer collectively to Diamondback Energy, Inc. and its subsidiaries other than the Company. References to the “General Partner” refer to Viper Energy Partners GP LLC, our general partner prior to the Conversion. All references to dividends prior to the Conversion refer to distributions.

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation. The Company reports its operations in one reportable segment.

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Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, geopolitical global conflicts, higher interest rates, effects of tariffs, actions taken by OPEC and its non-OPEC allies, known collectively as OPEC+, global supply chain disruptions, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of these events and changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves, including those acquired by the Company, and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third-party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties and estimates of income taxes, including deferred tax valuation allowances. Other areas requiring estimation include commodity derivatives and various fair values of non-oil and gas assets and liabilities.

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

The Company earns lease bonus income by leasing its mineral interests to exploration, development and production companies. The Company recognizes lease bonus income when a lease agreement has been executed and payment is determined to be collectible.

Royalty Income from Oil, Natural Gas and Natural Gas Liquids Sales

The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the operator of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

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Transaction Price Allocated to Remaining Performance Obligations

The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts.

Contract Balances

Under the Company’s royalty income contracts, it generally has the right to receive its interest in the gross proceeds collected by the operator from third-party purchasers of the Company’s production once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered. As a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s royalty interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the operator. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs from third parties are capitalized and amortized on a composite unit of production method based on proved oil, natural gas and natural gas liquids reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas and natural gas liquids. Acquisitions of mineral and royalty interests from related parties are typically recorded at the parent’s historical carrying value and related transaction costs are expensed as incurred in accordance with guidance in ASC 805 for transactions between entities under common control. At December 31, 2025, and 2024, the Company’s oil and natural gas properties consisted primarily of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.48, $11.77 and $10.20 for the years ended December 31, 2025, 2024 and 2023, respectively. Depletion for oil and natural gas properties was $607 million, $214 million and $146 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, (ii) the cost of properties not being amortized, if any, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5—Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property at least annually for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent of the operator to drill; remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the
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assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Royalty Income Receivable

Royalty income receivables consist of receivables for sales of oil, natural gas and natural gas liquids made by the Company’s third-party operators and Diamondback to third-party purchasers. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work, which is required to be completed by the operator before payments are released.

Royalty income receivables are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. Royalty income receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance utilizing the loss-rate method, which considers a number of factors, including the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific royalty income receivables when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2025 and 2024, the Company’s allowance for expected losses was immaterial.

Concentrations

The Company is subject to risk resulting from the concentration of its royalty income in producing oil and natural gas properties and receivables with several significant operators. For the year ended December 31, 2025, two operators each accounted for more than 10% of royalty income: Diamondback (55%) and ExxonMobil Corporation (14%). For the year ended December 31, 2024, two operators each accounted for more than 10% of royalty income: Diamondback (54%) and Pioneer Natural Resources (11%). For the year ended December 31, 2023, one operator accounted for more than 10% of royalty income: Diamondback (61%). Each of the Company’s operators sell to multiple purchasers. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Related Party Transactions

Royalty Income Receivable

As of December 31, 2025 and 2024, Diamondback, either directly or through its consolidated subsidiaries, owed the Company $88 million and $31 million, respectively, for royalty income received from third parties for the Company’s production, which had not yet been remitted to the Company.

Lease Bonus Income

During the year ended December 31, 2025, Diamondback and its subsidiaries paid the Operating Company $24 million of lease bonus income for 18 new leases covering 2,356 acres in Dawson, Glasscock, Howard, Martin, Midland and Reagan Counties, Texas. Lease bonus income from Diamondback for the year ended December 31, 2024 was immaterial. During the year ended December 31, 2023, Diamondback and its subsidiaries paid the Operating Company $108 million of lease bonus income, which included (i) one new lease of $96 million covering certain acreage in our Spanish Trail prospect in Midland County, Texas, from a lease agreement with a subsidiary of Diamondback on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback and was considered and approved by the conflicts committee of the board of directors, (ii) nine other new leases covering 703 acres in Martin, Midland, Pecos, and Wheeler Counties, Texas, and (iii) two lease extensions covering 25 acres in Martin County, Texas.

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Other Related Party Transactions

See Note 4—Acquisitions and Divestitures for significant related party acquisitions of oil and natural gas interests.

See Note 7—Stockholders’ Equity for further details regarding equity transactions with related parties.

All other related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements or were insignificant for the years ended December 31, 2025, 2024 and 2023, respectively.

Derivative Instruments

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2025, 2024 and 2023, there were no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. See Note 9—Income Taxes for further details.

Non-Controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, former equity holders of Sitio Royalties Operating Partnership, LP (“Sitio OpCo”), Tumbleweed Royalty IV, LLC (“TWR IV”) and the Morita Ranches Equity Recipients (as defined and discussed in Note 4—Acquisitions and Divestitures) in the net assets of the Operating Company. When the non-controlling interests’ relative ownership in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Company’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 7—Stockholders’ Equity for further discussion of changes in ownership interest.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The- Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

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Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following as of the dates indicated:

December 31,
20252024
(In millions)
Derivative instruments
$28 $18 
Prepaid expenses
13 11 
Other
9 2 
Total prepaid expenses and other current assets
$50 $31 

See “—Derivative Instruments” above for the Company’s accounting policy for derivative instruments.

Accrued Liabilities

The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value.

Accrued liabilities consist of the following as of the dates indicated:

December 31,
20252024
(In millions)
Interest payable$39 $10 
Ad valorem taxes payable34 20 
Acquisition adjustment accrual4 9 
2026 WTI Contingent Liability20 — 
Other10 4 
Total accrued liabilities$107 $43 

Debt Issuance Costs

Other assets include capitalized costs related to our current credit facility, the previous credit facility and the Term Loan (as defined and discussed in Note 6—Debt) of $21 million and $18 million, and accumulated amortization of those costs over the term of the respective credit facilities of $13 million and $11 million as of December 31, 2025 and 2024, respectively.

Long-term debt includes capitalized costs related to the Guaranteed Senior Notes. The costs associated with the Guaranteed Senior Notes are netted against the Guaranteed Senior Notes’ balances and amortized over the term of the Guaranteed Senior Notes using the effective interest method. See Note 6—Debt for further details.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The Company adopted the amendments in 2025 and applied the guidance on a retrospective basis. Adoption of the update resulted in additional disclosures in Note 9—Income Taxes but did not impact the Company’s financial position, results of operations or liquidity.

In September 2025, the FASB issued ASU 2025-07, “Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) – Derivatives Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract.” The ASU addresses (i) the application of derivative accounting to
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contracts that include features based on the operations or activities of one of the parties to the contract and (ii) diversity in practice related to accounting for share-based noncash consideration from a customer. The Company elected to early-adopt this amendment in 2025 and applied the guidance on a prospective basis. Adoption of the update did not impact the Company’s historical financial position, results of operations or liquidity; however, the guidance may affect whether certain new arrangements qualify for derivative accounting.

Accounting Pronouncements Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses,” which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained from third-party purchasers by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

For the years ended December 31, 2025, 2024 and 2023, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods were not material.

The following tables disaggregate the Company’s revenue from oil, natural gas and natural gas liquids by revenue generated from production on properties operated by Diamondback and revenue generated from production on properties operated by third parties:

Year Ended December 31, 2025
Revenue Generated from Diamondback Operated PropertiesRevenue Generated from Third-Party Operated PropertiesTotal
(In millions)
Oil income$612 $519 $1,131 
Natural gas income31 25 56 
Natural gas liquids income98 61 159 
Total royalty income$741 $605 $1,346 

Year Ended December 31, 2024
Revenue Generated from Diamondback Operated PropertiesRevenue Generated from Third-Party Operated PropertiesTotal
(In millions)
Oil income$398 $352 $750 
Natural gas income10 5 15 
Natural gas liquids income51 38 89 
Total royalty income$459 $395 $854 

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Year Ended December 31, 2023
Revenue Generated from Diamondback Operated PropertiesRevenue Generated from Third-Party Operated PropertiesTotal
(In millions)
Oil income$377 $242 $619 
Natural gas income16 15 31 
Natural gas liquids income42 25 67 
Total royalty income$435 $282 $717 

4.    ACQUISITIONS AND DIVESTITURES

2025 Activity

Sitio Acquisition

On August 19, 2025, the Company completed a series of transactions in which New Viper acquired Sitio Royalties Corp. (“Sitio”), Sitio OpCo and their respective subsidiaries, pursuant to the Agreement and Plan of Merger, dated June 2, 2025, by and among Former Viper, the Operating Company, Sitio, Sitio OpCo, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (the “Sitio Acquisition”). The Sitio Acquisition was an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The Company funded the retirement of Sitio’s net debt through a combination of cash on hand, proceeds from the issuance of the Guaranteed Senior Notes and borrowings under the Term Loan (as defined and discussed in Note 6—Debt).

Equity consideration for the Sitio Acquisition consisted of the right for Sitio and Sitio OpCo’s former equity holders to receive (i) 0.4855 shares of New Viper Class A Common Stock, for each share of Sitio Class A common stock, par value $0.0001 per share, and (ii) 0.4855 OpCo Units, along with a corresponding amount of New Viper Class B Common Stock, for each unit representing limited partnership interests of Sitio OpCo, subject to certain exclusions. The OpCo Units and New Viper Class B Common Stock issued in the Sitio Acquisition are exchangeable from time to time for shares of New Viper Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). Each share of Class C common stock, par value $0.0001 per share, of Sitio was automatically canceled in the transaction for no consideration and ceased to exist upon closing of the Sitio Acquisition. The shares of common stock of Former Viper and Sitio were delisted from the Nasdaq and their respective reporting obligations under the Exchange Act were terminated. As part of the Sitio Acquisition, New Viper issued 38,536,236 shares of Class A Common Stock, 35,619,951 shares of Class B Common Stock and 35,619,951 OpCo Units. In addition, at the closing of the Sitio Acquisition, the Company entered into a registration rights agreement with certain of Sitio OpCo’s former equity holders, pursuant to which such equity holders received certain demand registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock.

The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres. See Note 13—Subsequent Events for discussion of divestiture of the non-Permian acreage in 2026.

The Sitio Acquisition was accounted for as an asset acquisition in accordance with ASC 805.

2025 Drop Down

On May 1, 2025, the Company acquired all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC from Endeavor Energy Resources, LP (“Endeavor”), each a seller party and a subsidiary of Diamondback, pursuant to a definitive equity purchase agreement for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of the Company’s Class B Common Stock (the “2025 Drop Down”). The OpCo Units and the Class B Common Stock issued in the 2025 Drop Down, as well as the OpCo Units and Class B Common Stock otherwise beneficially owned by
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Diamondback, are exchangeable from time to time for shares of the Company’s Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). The shares of Class A Common Stock that may be issued to Diamondback and/or its subsidiaries upon exchange of their OpCo Units and shares of Class B Common Stock, including those OpCo Units and shares of Class B Common Stock issued at the closing of the 2025 Drop Down, are subject to the Company’s existing registration rights agreement with Diamondback, dated as of November 13, 2023, previously filed by the Company with the SEC.

The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback, and have an average net royalty interest of approximately 2.2% and then-current oil production of approximately 17,097 BO/d (the “Endeavor Mineral and Royalty Interests”). The Endeavor Mineral and Royalty Interests include interests in horizontal wells comprised of 5,574 gross proved developed production wells (of which approximately 32% are operated by Diamondback), 116 gross completed wells and 394 gross drilled but uncompleted wells, all of which are principally concentrated in the Midland Basin, with the balance located primarily in the Delaware and Williston Basins.

The 2025 Drop Down was approved by (i) the Company’s audit committee comprised of all independent directors and the full board of directors, in each case on January 30, 2025, and (ii) the majority of the Company’s stockholders, other than Diamondback and its subsidiaries, at the special meeting of the Company’s stockholders held on May 1, 2025, as required under the Nasdaq Rules.

The Company funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the 2025 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity) and borrowings under our previous revolving credit facility. The 2025 Drop Down was accounted for as a transaction between entities under common control, with the Endeavor Mineral and Royalty Interests recorded at Endeavor’s historical carrying value in the Company’s consolidated balance sheet.

Morita Ranches Acquisition

On February 14, 2025, the Company completed an acquisition of certain mineral and royalty interests located in Howard County, Texas from Morita Ranches Minerals, LLC (“Morita Ranches”) (the “Morita Ranches Acquisition”) pursuant to a definitive purchase and sale agreement for consideration consisting of approximately (i) $208 million in cash, and (ii) 2,400,297 OpCo Units together with an equal number of shares of the Company’s Class B Common Stock issued to certain affiliate designees of Morita Ranches (the “Morita Ranches Equity Recipients”), including customary transaction costs and post-closing adjustments. At the closing of the Morita Ranches Acquisition, the Morita Ranches Equity Recipients (i) became parties to the Third Amended and Restated Limited Liability Agreement of the Operating Company, dated as of October 1, 2024, as amended, and (ii) entered into an Exchange Agreement with the Company and the Operating Company to provide for the right to exchange the OpCo Units and shares of the Company’s Class B Common Stock acquired by the Morita Ranches Equity Recipients at the closing of the Morita Ranches Acquisition for an equal number of shares of the Company’s Class A Common Stock. In addition, at the closing of the Morita Ranches Acquisition, the Company entered into a registration rights agreement pursuant to which the Morita Ranches Equity Recipients received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock.

The mineral and royalty interests included in the Morita Ranches Acquisition represent approximately 1,691 net royalty acres in the Permian Basin, 75% of which are operated by Diamondback, and have an average net royalty interest of approximately 10.9%. The Company funded the cash consideration for the Morita Ranches Acquisition with proceeds from the 2025 Equity Offering. The Morita Ranches Acquisition was accounted for as an asset acquisition in accordance with ASC 805.

Other Acquisitions

During the year ended December 31, 2025, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $140 million, including customary closing adjustments. In the second half of 2025, the Company acquired, in individually insignificant transactions from Diamondback E&P LLC, mineral and royalty interests representing 80 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $2 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our revolving credit facility.

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Notes to Consolidated Financial Statements - (Continued)
2024 Activity

Acquisitions

Tumbleweed Acquisitions

In September and October of 2024, the Company completed a series of related acquisitions including the TWR Acquisition, the Q Acquisition and the M Acquisition (collectively the “Tumbleweed Acquisitions”), each as defined and discussed below.

TWR Acquisition

On October 1, 2024, the Company acquired all of the issued and outstanding equity interests in TWR IV, LLC and TWR IV SellCo, LLC from TWR IV and TWR IV SellCo Parent, LLC (the “TWR Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $464 million in cash, including transaction costs and certain customary post-closing adjustments, (ii) 10,093,670 OpCo Units to TWR IV, (iii) an option granted to TWR IV to acquire up to 10,093,670 shares of the Company’s Class B Common Stock (the “TWR Class B Option”), and (iv) contingent cash consideration of $16 million paid in January 2026 (the “TWR Contingent Liability”) based on the average price of WTI sweet crude oil prompt month futures contracts for the calendar year 2025 (the “WTI 2025 Average”), which was between $60.00 and $65.00. Additionally, at the closing of the TWR Acquisition, the Company assumed a royalty income receivable of approximately $24 million.

TWR IV can exchange some or all of its OpCo Units for an equal number of shares of the Company’s Class A Common Stock and any OpCo Units so exchanged will reduce the number of shares of Class B Common Stock subject to the TWR Class B Option. In addition, at the closing of the TWR Acquisition, the Company entered into a registration rights agreement with TWR IV, pursuant to which TWR IV received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by TWR IV in exchange for OpCo Units. The mineral and royalty interests acquired in the TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin. The Company funded the cash consideration for the TWR Acquisition through a combination of cash on hand, borrowings under our previous revolving credit facility and proceeds from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity).

Q Acquisition

On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (the “Q Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “Q Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the Q Acquisition represent approximately 406 net royalty acres located primarily in the Permian Basin. The cash consideration for the Q Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility.

M Acquisition

On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in MC TWR Royalties, LP and MC TWR Intermediate, LLC (the “M Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “M Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the M Acquisition represent approximately 267 net royalty acres located primarily in the Permian Basin. The cash consideration for the M Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility.

The Q Contingent Liability, the M Contingent Liability and the TWR Contingent Liability are collectively referred to as the “2026 WTI Contingent Liability.”

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Other Acquisitions

In addition to the acquisitions discussed above, during the year ended December 31, 2024, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 261 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $54 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility.

Divestiture

In the second quarter of 2024, the Company divested all of its non-Permian assets for a purchase price of approximately $87 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 2,713 net royalty acres with current production of approximately 450 BO/d. The Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale.

2023 Activity

Acquisitions

GRP Acquisition

On November 1, 2023, the Company acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP, affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement for 9,018,760 common units and $747 million in cash, including transaction costs and certain customary post-closing adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired in the GRP Acquisition represent approximately 4,600 net royalty acres in the Permian Basin, and approximately 2,700 additional net royalty acres in other major basins. The cash consideration for the GRP Acquisition was funded through a combination of cash on hand and held in escrow, borrowings under our previous revolving credit facility, proceeds from the 2031 Notes (as defined and discussed in Note 6—Debt) and proceeds from the $200 million common unit issuance to Diamondback discussed further in Note 7—Stockholders’ Equity.

2023 Drop Down

On March 8, 2023, the Company acquired certain mineral and royalty interests from subsidiaries of Diamondback for approximately $75 million in cash, including customary closing adjustments for net title benefits (the “2023 Drop Down”). The mineral and royalty interests acquired in the 2023 Drop Down represented approximately 660 net royalty acres in Ward County, Texas in the Southern Delaware Basin, 100% of which were operated by Diamondback, and had an average net royalty interest of approximately 7.2% and then-current production of approximately 300 BO/d. The Company funded the 2023 Drop Down through a combination of cash on hand and borrowings under our previous revolving credit facility. The 2023 Drop Down was accounted for as a transaction between entities under common control with the acquired properties recorded at Diamondback’s historical carrying value in the Company’s consolidated balance sheet. The historical carrying value of the properties approximated the 2023 Drop Down purchase price.

Other Acquisitions

Additionally during the year ended December 31, 2023, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 286 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $70 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility.

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Notes to Consolidated Financial Statements - (Continued)
5.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following for the periods presented:

December 31,
20252024
(In millions)
Oil and natural gas interests:
Proved properties$9,746 $3,533 
Unproved properties4,910 2,180 
Gross oil and natural gas interests14,656 5,713 
Accumulated depletion(1,567)(961)
Accumulated impairment(888)(120)
Oil and natural gas interests, net12,201 4,632 
Other property, equipment and land8 6 
Property, net of accumulated depletion and impairment$12,209 $4,638 
Balance of costs not subject to depletion:
Incurred in 2025$3,614 
Incurred in 2024562 
Incurred in 2023553 
Prior181 
Total not subject to depletion$4,910 

As of December 31, 2025, and 2024, the Company had mineral and royalty interests representing approximately 96,003 and 35,671 net royalty acres, respectively.

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves can be made. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within nine to 12 years. All costs incurred not subject to depletion are classified as acquisition costs.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. As a result of its ceiling test, the Company recorded aggregate non-cash ceiling test impairments for the year ended December 31, 2025 of $768 million. No impairment expense was recorded on the Company’s oil and natural gas interests for the years ended December 31, 2024 and 2023, based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Company’s production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If future SEC Prices decline as compared to the commodity prices used in prior quarters, the Company could have further write-downs in subsequent quarters, which may be material.

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Notes to Consolidated Financial Statements - (Continued)
6.    DEBT

Long-term debt consisted of the following as of the dates indicated:

December 31,
20252024
(In millions)
5.375% Senior Notes due 2027
$— $430 
4.900% Senior Notes due 2030
500 — 
7.375% Senior Notes due 2031
— 400 
5.700% Senior Notes due 2035
1,100 — 
Term Loan500 — 
Revolving credit facility105 261 
Unamortized debt issuance costs(15)(6)
Unamortized discount costs(4)(2)
Total long-term debt$2,186 $1,083 

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent (the “2025 Revolving Credit Facility”), which among other things, provides the borrower with a senior unsecured revolving credit facility with a commitment of $1.5 billion, a swingline commitment of up to $50 million and a letter of credit commitment of $5 million. The 2025 Revolving Credit Facility has a maturity date of June 12, 2030, with the ability to request three extensions of the maturity date by one year. The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the borrower, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced the borrower’s previous revolving credit facility, dated July 20, 2018, among the Company, the borrower and Wells Fargo as amended, restated, amended and restated, supplemented or otherwise modified prior to June 12, 2025. As of December 31, 2025, there was $105 million in outstanding borrowings and $1.4 billion available for future borrowings under the 2025 Revolving Credit Facility. For the years ended December 31, 2025, 2024 and 2023, the weighted average interest rates on borrowings under the borrower’s respective revolving credit facilities were 6.02%, 7.34%, and 7.41%, respectively.

Borrowings under the 2025 Revolving Credit Facility bear interest at a per annum rate elected by the borrower that is equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate loans and from 1.125% to 2.000% per annum in the case of term SOFR loans, in each case based on the pricing level. Further, the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitment, again based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies.

The 2025 Revolving Credit Facility contains a financial covenant that requires the Company to maintain a Total Net Debt to Capitalization Ratio (as defined in the 2025 Revolving Credit Facility) of no more than 65%. As of December 31, 2025, the borrower was in compliance with all financial maintenance covenants under the 2025 Revolving Credit Facility.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which thereupon became the borrower with respect to the 2025 Revolving Credit Facility.

Term Loan

On July 23, 2025, in connection with the Sitio Acquisition, Former Viper, as guarantor, entered into a term loan credit agreement with the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, (the “Term Loan”).
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The Term Loan provided the Company with the ability to borrow up to $500 million on a senior unsecured basis to fund a portion of the retirement of Sitio’s net debt, in connection with the Sitio Acquisition. On August 19, 2025, the date of closing of the Sitio Acquisition, the Term Loan was fully drawn in a single borrowing. Any then-outstanding amounts will mature and be payable in full on the second anniversary of the initial funding date. In connection with the closing of the Sitio Acquisition, New Viper became a co-guarantor of the Term Loan. During the year ended December 31, 2025, the weighted average interest rate on borrowings under the Term Loan was 5.72%.

Borrowings under the Term Loan bear interest at a per annum rate elected by the borrower that is equal to SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies. In addition, the fee on undrawn commitments is equal to 0.20% per annum on the aggregate principal amount of such commitments.

Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

Guaranteed Senior Notes Offering

On July 23, 2025, the Operating Company, as issuer, and Former Viper, as guarantor, issued $1.6 billion in aggregate principal amount of the Guaranteed Senior Notes consisting of (i) $500 million aggregate principal amount of 4.900% Senior Notes due August 1, 2030, (the “2030 Notes”), and (ii) $1.1 billion aggregate principal amount of 5.700% Senior Notes due August 1, 2035, (the “2035 Notes”). The Company received net proceeds of approximately $1.58 billion, after underwriters’ discounts and transaction costs. Interest on the Guaranteed Senior Notes is payable semi-annually in February and August of each year, beginning on February 1, 2026. Concurrently, the Company used approximately $824 million of the proceeds to redeem approximately $780 million in aggregate principal amounts of the Company’s outstanding Notes, including accrued interest due and applicable redemption premiums. Following the closing of the Sitio Acquisition, the Company used the remaining proceeds from the issuance of the Guaranteed Senior Notes to (i) retire Sitio’s 7.875% senior notes due 2028, (ii) partially repay borrowings under Sitio’s revolving credit facility, (iii) pay fees, costs and expenses related to the redemption or repayment of such debt, and (iv) for general corporate purposes.

The Guaranteed Senior Notes (i) are senior unsecured obligations and are fully and unconditionally guaranteed by Former Viper, and, following the closing of the Sitio Acquisition, also by New Viper, (ii) are senior in right of payment to any of the Company’s future subordinated indebtedness, and (iii) rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The Guaranteed Senior Notes have been registered under the Securities Act.

Following the OpCo Conversion, Viper LP became the issuer with respect to the Guaranteed Senior Notes.

Retirement of Notes

During the second quarter of 2025, the Company opportunistically repurchased principal amounts of $50 million of its 5.375% Senior Notes due 2027 (the “2027 Notes”) in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value, resulting in an immaterial gain on extinguishment of debt for the year ended December 31, 2025.

On July 23, 2025, using proceeds from the issuance of the Guaranteed Senior Notes, the Company (i) redeemed all of its outstanding 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”), which were issued in October 2023 to partially fund the cash portion of the GRP Acquisition, for total cash consideration of approximately $434 million including the applicable redemption premium of 106.767% of par and accrued and unpaid interest up to, but not including, the redemption date, and (ii) deposited approximately $390 million to redeem all of its outstanding 2027 Notes on November 1, 2025, for total cash consideration, including payment of interest due to, but not including, the redemption date at a redemption price equal to 100% of the principal amount of the 2027 Notes. The redemption of the 2031 Notes resulted in a loss on extinguishment of debt of $32 million.

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Viper Energy, Inc.
Notes to Consolidated Financial Statements - (Continued)
Interest Expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2025, 2024 and 2023:

Year Ended December 31,
202520242023
(In millions)
Interest expense$103 $74 $48 
Other fees and expenses3 2 1 
Less: interest income10 2 2 
Interest expense, net$96 $74 $47 

7.    STOCKHOLDERS’ EQUITY

At December 31, 2025, the Company had a total of 170,942,687 shares of Class A Common Stock issued and outstanding and 187,023,698 shares of Class B Common Stock issued and outstanding. Additionally, at December 31, 2025, TWR IV held the TWR Class B Option to acquire up to 10,093,670 shares of the Company’s Class B Common Stock.

In connection with the Reorganization, Viper in its position as managing member of New OpCo, along with affiliates of Diamondback, TWR IV and the Morita Ranches Equity Recipients adopted the Amended and Restated Limited Liability Company Agreement of New OpCo (the “New OpCo LLC Agreement”). The New OpCo LLC Agreement provides that members of New OpCo may require the Company to redeem all or a portion of the shares of the Company’s Class B Common Stock held by such member, together with an equal number of OpCo Units (one share of Class B Common Stock together with one OpCo Unit) in exchange for (i) an equivalent number of shares of the Company’s Class A Common Stock, or (ii) cash consideration subject to the terms and conditions included in the New OpCo LLC Agreement.

The following table presents the beneficial ownership of Common Stock and OpCo Units as of December 31, 2025:

As of December 31, 2025
Shares of Common Stock Beneficially Owned
Percentage Ownership(1)
OpCo Units Beneficially Owned
Percentage Ownership
Public equity holders of Class A Common Stock
170,942,687 46.5 %— — %
Viper and subsidiaries
— — %170,942,687 46.5 %
Diamondback and subsidiaries
155,058,093 42.1 %155,058,093 42.1 %
Sitio OpCo former equity holders
29,565,308 8.0 %29,565,308 8.0 %
TWR IV(1)
10,093,670 2.7 %10,093,670 2.7 %
Morita Ranches Equity Recipients
2,400,297 0.7 %2,400,297 0.7 %
Total Ownership(1)
368,060,055 100.0 %368,060,055 100.0 %
(1)On a fully diluted basis, assuming TWR IV exercises the TWR Class B Option.

2025 Equity Offering

On February 3, 2025, the Company completed an underwritten public offering of 28,336,000 shares of Class A Common Stock, which included 3,696,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $44.50 per share for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “2025 Equity Offering”). The Company used the net proceeds from the 2025 Equity Offering to fund (i) the cash consideration for the Morita Ranches Acquisition, (ii) a portion of the cash consideration for the 2025 Drop Down, and (iii) for general corporate purposes.

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Notes to Consolidated Financial Statements - (Continued)
2024 Equity Offering

On September 13, 2024, the Company completed an underwritten public offering of 11,500,000 shares of Class A Common Stock, which included 1,500,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $42.50 per share for total net proceeds of approximately $476 million, after the underwriters’ discount and transaction costs (the “2024 Equity Offering”). The net proceeds were used to fund a portion of the cash consideration for the TWR Acquisition.

2023 Viper Issuance of Common Units to Diamondback

In October 2023, the Company issued 7,215,007 of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200 million. The net proceeds were used to fund a portion of the cash consideration for the GRP Acquisition. During 2024, Diamondback sold all of its shares of the Company’s Class A Common Stock in the Diamondback Offering discussed in Note 1—Organization and Basis of Presentation.

Repurchase Program

Previously, the Company’s board of directors authorized a $750 million repurchase program, with respect to the repurchase of the Company’s Class A Common Stock, excluding excise tax, over an indefinite period of time. On December 10, 2025, the Company’s board of directors expanded the repurchase program to also include repurchases of the Company’s Class B Common Stock and OpCo Units. The Company has purchased and intends to continue to purchase shares of Common Stock and OpCo Units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended, modified or extended, from time to time, or may be discontinued at any time, in each case, by the Company’s board of directors.

During the year ended December 31, 2025, repurchases under the repurchase program totaled $194 million, which includes approximately $41 million for the repurchase of 1,000,000 OpCo Units from an affiliate of Kimmeridge Energy Management Company, LLC (“Kimmeridge”) in a privately negotiated transaction on December 10, 2025. Concurrently, a corresponding number of shares of the Company’s Class B Common Stock owned by Kimmeridge were cancelled. During the year ended December 31, 2024, there were no repurchases under the repurchase program. Repurchases of $95 million for the year ended December 31, 2023, include approximately $29 million for the repurchase of 1,000,000 shares of Class A Common Stock from GRP in a privately negotiated transaction in the fourth quarter of 2023. As of December 31, 2025, $241 million remains available under the repurchase program, excluding excise tax.

Cash Dividends

The board of directors of the Company has established a dividend policy, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to holders of the OpCo Units. Viper in turn distributes all or a portion of the available cash it receives from the Operating Company to holders of its Class A Common Stock through base and variable dividends that take into account capital returned to stockholders via its repurchase program. The Company’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors following the end of such quarter. The Company’s dividend policy currently requires the Company to pay quarterly variable dividends of at least 75% of its available cash less the base dividend declared and the amount paid for repurchases of the Company’s Common Stock and OpCo Units as part of its repurchase program for the applicable quarter. Additionally, the Company’s board of directors may approve certain one-time discretionary adjustments to the calculation of cash available for distribution.

The Company expects that its available cash will generally equal the Adjusted EBITDA attributable to the Company for the applicable quarter, less cash needed for income taxes payable; debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the Company’s board of directors deems necessary or appropriate; lease bonus income (net of applicable taxes); dividend equivalent rights payments; preferred distributions and an adjustment for changes in ownership interests that occurred subsequent to the quarter, if any.

The percentage of cash available for distribution by the Operating Company pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Company’s balance sheet while also expanding the return of capital program through the Company’s repurchase program. The Company is not required to pay dividends to the holders of its Class A Common Stock on a quarterly or other basis.

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The Company is also required to pay a quarterly preferred dividend in respect of its Class B Common Stock in the aggregate amount of $20,000 per quarter, which is consistent with the Partnership’s pre-Conversion preferred distribution requirement. Other than the preferred dividend requirement, the Company is not required to pay dividends to the holders of its Common Stock on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of the Company’s board of directors.

The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2025, 2024 and 2023 (in millions except per share amounts):

Distributions
PeriodAmount per OpCo Unit
Operating Company Distributions to Non-Controlling Interests
Amount per Class A Common Share
Class A Common Stockholders(1)(2)
Declaration DateClass A Common Stockholder Record DatePayment Date
2025
Q4 2024$0.69 $68 $0.65 $85 January 30, 2025March 6, 2025March 13, 2025
Q1 2025$0.70 $117 $0.57 $75 May 1, 2025May 15, 2025May 22, 2025
Q2 2025$0.59 $98 $0.53 $68 July 31, 2025August 14, 2025August 21, 2025
Q3 2025$0.66 $134 $0.58 $99 October 30, 2025November 13, 2025November 20, 2025
2024
Q4 2023$0.69 $63 $0.56 $48 February 15, 2024March 5, 2024March 12, 2024
Q1 2024$0.70 $60 $0.59 $54 April 25, 2024May 15, 2024May 22, 2024
Q2 2024$0.76 $65 $0.64 $59 August 1, 2024August 15, 2024August 22, 2024
Q3 2024$0.73 $69 $0.61 $63 October 31, 2024November 14, 2024November 21, 2024
2023
Q4 2022$0.54 $49 $0.49 $36 February 15, 2023March 3, 2023March 10, 2023
Q1 2023$0.42 $38 $0.33 $24 April 26, 2023May 11, 2023May 18, 2023
Q2 2023$0.44 $40 $0.36 $25 July 25, 2023August 10, 2023August 17, 2023
Q3 2023$0.70 $64 $0.57 $49 November 2, 2023November 16, 2023November 24, 2023
(1)Dividends paid in the first quarter of 2024 include amounts paid to Diamondback for the 7,946,507 shares of Class A Common Stock then beneficially owned by Diamondback and distributions equivalent rights payments. As of March 31, 2024, Diamondback did not beneficially own any shares of Class A Common Stock.
(2)For distributions paid in 2023, includes amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback.

Cash dividends will be made to the holders of record of the Company’s Class A Common Stock on the applicable record date, generally within 60 days after the end of each quarter.

Changes in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, Sitio OpCo’s former equity holders, TWR IV and the Morita Ranches Equity Recipients in the net assets of the Operating Company. The non-controlling interests’ relative ownership in the Operating Company can change due to the purchase or sale of the Company’s Common Stock, the Company’s public offerings of shares of Class A Common Stock for which proceeds are contributed to the Operating Company in exchange for OpCo Units, issuance of shares of Class A Common Stock or issuance of shares of Class B Common Stock and OpCo Units for acquisitions, share-based compensation, repurchases of shares of Common Stock or OpCo Units and dividend equivalent rights paid on the Company’s Class A Common Stock. These changes in ownership percentage result in adjustments to non-controlling interest and stockholders’ equity, tax effected, but do not impact earnings.

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Notes to Consolidated Financial Statements - (Continued)
The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period:

Year Ended December 31,
202520242023
(In millions)
Net income (loss) attributable to the Company$(68)$359 $200 
Change in ownership of consolidated subsidiaries 448 59 (102)
Change from net income (loss) attributable to the Company’s stockholders and transfers with non-controlling interest$380 $418 $98 

8.    EARNINGS PER COMMON SHARE

The net income (loss) per common share on the consolidated statements of operations is based on the net income (loss) attributable to the Company’s Class A Common Stock for the years ended December 31, 2025, 2024 and 2023.

Basic and diluted earnings per common share are calculated using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of Class A Common Stock and participating securities. Basic net income (loss) per common share is calculated by dividing net income (loss) by the weighted-average shares of Class A Common Stock outstanding during the period. Diluted net income (loss) per common share gives effect, when applicable, to unvested restricted stock units and performance restricted stock units granted under the LTIP.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

Year Ended December 31,
202520242023
(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to the period$(68)$359 $200 
Less: net income (loss) allocated to participating securities(1)
1 — — 
Net income (loss) attributable to common stockholders$(69)$359 $200 
Weighted average common shares outstanding:
Basic weighted average common shares outstanding142,530 93,932 74,176 
Effect of dilutive securities:
Potential common shares issuable(2)
— — — 
Diluted weighted average common shares outstanding142,530 93,932 74,176 
Net income (loss) per common share, basic$(0.48)$3.82 $2.69 
Net income (loss) per common share, diluted$(0.48)$3.82 $2.69 
(1)Unvested restricted stock units and performance restricted stock units that contain non-forfeitable dividend equivalent rights are considered participating securities and are therefore included in the earnings per share calculation pursuant to the two-class method.
(2)For the year ended December 31, 2025, 110,342 potential common shares were excluded from the computation of diluted earnings per common share because their inclusion would have been anti-dilutive as a result of recording a net loss attributable to the common shareholders for the period. For the years ended December 31, 2024 and 2023 no significant potential common shares were excluded from the computation of diluted earnings per common share.

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Notes to Consolidated Financial Statements - (Continued)
9.    INCOME TAXES

The Company’s total income tax benefit for the year ended December 31, 2025, differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to net loss attributable to the non-controlling interest. For the year ended December 31, 2024, the Company’s total income tax benefit differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the release of the remaining valuation allowance during the fourth quarter and net income attributable to non-controlling interests. For the year ended December 31, 2023, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of reductions to the valuation allowance.

The components of the provision for income taxes for the years ended December 31, 2025, 2024 and 2023 are as follows:

Year Ended December 31,
202520242023
(In millions)
Current income tax provision (benefit):
Federal$60 $47 $50 
State4 2 3 
Total current income tax provision (benefit)64 49 53 
Deferred income tax provision (benefit):
Federal(78)(148)(7)
State(5)(1)— 
Total deferred income tax provision (benefit)(83)(149)(7)
Total provision (benefit) from income taxes$(19)$(100)$46 

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

Year Ended December 31,
202520242023
Amount
(In millions)
Percentage of Income (Loss) Before Income Taxes
Amount
(In millions)
Percentage of Income (Loss) Before Income Taxes
Amount
(In millions)
Percentage of Income (Loss) Before Income Taxes
Income tax expense (benefit) at the federal statutory rate (21%)$(47)21 %$106 21 %$115 21 %
State income tax, net of federal income tax effect(1)
(1)— %2 — %2 — %
Changes in valuation allowances— — %(156)(31)%(8)(1)%
Nontaxable or nondeductible items:
Impact of nontaxable noncontrolling interest29 (13)%(52)(10)%(63)(12)%
Provision for (benefit from) income taxes$(19)8 %$(100)(20)%$46 8 %
(1)State taxes in Texas make up the majority (greater than 50%) of the tax effect in this category.

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Viper Energy, Inc.
Notes to Consolidated Financial Statements - (Continued)
The components of the Company’s deferred tax assets and liabilities as of December 31, 2025 and 2024 are as follows:

Year Ended December 31,
20252024
(In millions)
Deferred tax assets:
Net operating loss and capital loss carryforwards$5 $— 
Investment in the Operating Company28 185 
Total deferred tax assets33 185 
Valuation allowance— — 
Net deferred tax assets33 185 
Net deferred tax assets (liabilities)$33 $185 

At December 31, 2025, the Company had net deferred tax assets of approximately $33 million, including $5 million in federal capital loss carryforwards expiring in 2027 and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Company’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company.

In connection with the closing of the Sitio Acquisition, the Company acquired prepaid income tax balances of approximately $14 million and deferred tax assets of $5 million related to loss carryforwards. The Company also recognized a deferred tax liability of approximately $122 million. The Company’s federal loss carryforwards acquired from Sitio are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which subjects tax attributes to limitation upon an “ownership change” (as defined in the Code). In general, an ownership change occurs if there is a cumulative increase in the ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year look back period. Based on Sitio’s fair market value, the Company has determined that the applicable annual limitation exceeds the loss carryforwards acquired from Sitio. As such, the Company believes that the application of Section 382 of the Code will not have an adverse effect on future usage of its federal tax attributes.

During the fourth quarter of 2024, the Company released its remaining valuation allowance of $156 million as a result of management’s assessment of the realizability of future taxable income, which primarily contributed to the discrete income tax benefit of $149 million for the year ended December 31, 2024. During the year ended December 31, 2023, the Company recognized a discrete income tax benefit of $7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years.

In March 2024, as part of the Diamondback Offering, the Company recognized a $28 million increase in its deferred tax asset and an $11 million increase in its valuation allowance through additional paid-in capital.

At December 31, 2025, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The Company’s 2022 through 2025 tax years remain open to examination by tax authorities.

On July 4, 2025, H.R. 1, commonly known as the One Big Beautiful Bill Act (the “OBBB”), was enacted. The OBBB included multiple provisions applicable to U.S. income taxes for businesses, including immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the corporate “book” minimum tax and enhancements to limits on business interest expense deductions. The Company accounted for the OBBB in the period of enactment and concluded there was not a material impact to the Company’s current or deferred income tax balances.

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Notes to Consolidated Financial Statements - (Continued)
10.    DERIVATIVES

Commodity Contracts

The Company historically has used fixed price swap contracts, fixed price basis swap contracts, deferred premium puts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2025, the Company has puts, costless collars and fixed price basis swap contracts outstanding.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on WTI Cushing and fixed price basis swaps for oil based on the spread between the WTI Cushing crude oil price and the Argus WTI Midland crude oil price. The Company’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the WTI Cushing oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Under the Company’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Company, and when the settlement price is above the ceiling price, the Company is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under the 2025 Revolving Credit Facility and our counterparties have been deemed an acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding commodity derivative contracts. Market risks involved in the Company’s use of derivative instruments relate to its potential inability to realize the benefits of any increases in commodity prices above the prices established by its derivative contracts.

As of December 31, 2025, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

SwapsCollarsPuts
Settlement MonthSettlement YearType of ContractBbls/MMBtu Per DayIndexWeighted Average DifferentialWeighted Average Floor PriceWeighted Average Ceiling PriceStrike PriceDeferred Premium
OIL
Jan. - Mar.2026Puts40,000WTI Cushing$—$—$—$51.75$(1.56)
Apr. - Jun.2026Puts20,000WTI Cushing$—$—$—$48.13$(1.35)
NATURAL GAS
Jan. - Dec.2026Basis Swaps80,000Waha Hub$(1.61)$—$—$—$—
Jan. - Dec.2027Basis Swaps40,000Waha Hub$(1.40)$—$—$—$—
Jan. - Dec.2026Costless Collar60,000Henry Hub$—$2.75$6.64$—$—

Treasury Locks

During the third quarter of 2025, the Company entered into certain treasury lock contracts to reduce the forecasted interest rate risk associated with the issuance of the Guaranteed Senior Notes. The treasury locks were terminated and settled upon issuance of the Guaranteed Senior Notes with a gain of $3 million recognized under the caption “Gain (loss) on derivative instruments, net” on the consolidated statements of operations for the year ended December 31, 2025.

Contingent Liability

The change in fair value of the 2026 WTI Contingent Liability is recognized in “Gain (loss) on derivative instruments, net” on the Company’s consolidated statements of operations for the years ended December 31, 2025 and 2024.

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Notes to Consolidated Financial Statements - (Continued)
Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:

Year Ended December 31,
202520242023
(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts$31 $15 $(26)
2026 WTI Contingent Liability10 (4)— 
Treasury locks3 — — 
Total$44 $11 $(26)
Net cash receipts (payments) on derivatives:
Commodity contracts$27 $(3)$(13)
Treasury locks3 — — 
Total$30 $(3)$(13)

11.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

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Notes to Consolidated Financial Statements - (Continued)
Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s commodity derivative instruments and the 2026 WTI Contingent Liability.

The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third-party, the contracted notional volumes and time to maturity. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The fair value of the 2026 WTI Contingent Liability was estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.

The following tables provide (i) the consolidated balance sheet classification where the Company’s commodity derivative instrument assets and liabilities and 2026 WTI Contingent Liability are recorded, (ii) fair value measurement information, (iii) the gross amounts of recognized assets and liabilities, (iv) the amounts offset under master netting arrangements with counterparties, and (v) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2025, and December 31, 2024:

As of December 31, 2025
Balance Sheet ClassificationLevel 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In millions)
Assets:
Prepaid expenses and other current assets$— $37 $— $37 $(9)$28 
Liabilities:
Other current liabilities$— $9 $— $9 $(9)$— 
Accrued liabilities (2026 WTI Contingent Liability)
$— $20 $— $20 $— $20 
Other long-term liabilities$— $7 $— $7 $— $7 

As of December 31, 2024
Balance Sheet ClassificationLevel 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In millions)
Assets:
Prepaid expenses and other current assets$— $24 $— $24 $(6)$18 
Liabilities:
Other current liabilities$— $8 $— $8 $(6)$2 
Accrued liabilities (2026 WTI Contingent Liability)
$— $30 $— $30 $— $30 

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Notes to Consolidated Financial Statements - (Continued)
Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:

December 31, 2025December 31, 2024
Carrying ValueFair ValueCarrying ValueFair Value
(In millions)
Debt
$2,186 $2,233 $1,083 $1,105 

The fair values of our current or previous revolving credit facility, as applicable, and the Term Loan approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair values of the Notes and Guaranteed Senior Notes were determined using the quoted market price at each period end, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of the Company’s proved oil and natural gas interests to fair value when they are impaired or held for sale.

See Note 2—Summary of Significant Accounting Policies and Note 5—Oil and Natural Gas Interests for further discussion of non-recurring fair value adjustments.

Fair Value of Financial Assets

The Company has other financial instruments consisting of cash and cash equivalents, royalty income receivable, income tax receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

12.    COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of any pending proceedings, disputes or claims and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

13.    SUBSEQUENT EVENTS

Cash Dividend

On February 18, 2026, our board of directors approved an increase to the Company’s annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025. Our board of directors further approved a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case, payable on March 12, 2026, to holders of record at the close of business on March 5, 2026. The dividend on Class A Common Stock consists of a base quarterly dividend of $0.38 per share and a variable quarterly dividend of $0.14 per share.

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Notes to Consolidated Financial Statements - (Continued)
Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under the Company’s existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax.

Divestiture of Non-Permian Assets

On February 9, 2026, the Company divested all of its non-Permian assets, including those acquired from Sitio, to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the divestiture were used to (i) repay the Company’s $500 million Term Loan in full, (ii) fully repay $90 million of then-outstanding borrowings under the 2025 Revolving Credit Facility, and (iii) for general corporate purposes.

14.    SEGMENT INFORMATION

As of December 31, 2025, the Company is managed on a consolidated basis as a single operating and reportable segment which is focused on owning and acquiring mineral and royalty interests primarily in the Permian Basin in West Texas. The Company’s operating segment primarily derives its revenue from customers through the receipt of royalty income on the sale of oil and natural gas products as well as other immaterial service contracts. See Note 3—Revenue from Contracts with Customers for further discussion of the Company’s sources of revenue.

The Company’s Chief Operating Decision Maker (“CODM”) is a senior executive committee that is comprised of the Company’s Chief Executive Officer and President. The CODM uses the Company’s consolidated financial results to assess performance, allocate resources and make key operating decisions, obtaining the board’s approval as required. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets, as reported on the consolidated statements of operations and the consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s consolidated statements of operations as well as interest income and interest expense in Note 6—Debt.

The CODM uses consolidated net income as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or return of capital through the payment of base and variable dividends or repurchases under the share repurchase program.

15.    SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

December 31,
20252024
(In millions)
Oil and natural gas interests:
Proved$9,746 $3,533 
Unproved4,910 2,180 
Total oil and natural gas interests14,656 5,713 
Accumulated depletion(1,567)(961)
Accumulated impairment(888)(120)
Net oil and natural gas interests capitalized$12,201 $4,632 

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Notes to Consolidated Financial Statements - (Continued)
Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil and natural gas property acquisition activities are as follows:

Year Ended December 31,
202520242023
(In millions)
Acquisition costs:
Proved properties$4,976 $341 $403 
Unproved properties3,968 830 758 
Total$8,944 $1,171 $1,161 

Results of Operations from Oil and Natural Gas Producing Activities

Substantially all of the Company’s producing activities are from oil and natural gas activities and are included in the “—Consolidated Statements of Operations.”

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The reserve estimates represent the Company’s net revenue interest in the Company’s properties. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon SEC Prices for the periods ended December 31, 2025, 2024 and 2023, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. All of the Company’s proved reserves included in the reserve reports are located in the continental United States. Although the estimates are believed to be reasonable, actual future production, cash flows, taxes and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

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Notes to Consolidated Financial Statements - (Continued)
The following table presents changes in estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC:

Oil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)
Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 202279,004 209,964 34,902 148,900 
Purchase of reserves in place10,469 27,011 4,006 18,977 
Extensions and discoveries13,636 34,632 6,150 25,558 
Revisions of previous estimates(5,178)11,101 3,466 138 
Production(8,028)(19,130)(3,108)(14,324)
As of December 31, 202389,903 263,578 45,416 179,249 
Purchase of reserves in place7,891 20,310 3,665 14,941 
Extensions and discoveries13,099 33,498 6,254 24,936 
Revisions of previous estimates(6,472)4,449 2,837 (2,894)
Divestitures(919)(4,605)(451)(2,138)
Production(9,939)(24,606)(4,181)(18,221)
As of December 31, 202493,563 292,624 53,540 195,873 
Purchase of reserves in place90,168 336,127 55,102 201,291 
Extensions and discoveries31,305 90,973 15,702 62,170 
Revisions of previous estimates(3,951)(31,751)(9,328)(18,570)
Divestitures(4)(12)(2)(8)
Production(17,875)(51,676)(8,233)(34,721)
As of December 31, 2025193,206 636,285 106,781 406,035 
Proved Developed Reserves:
December 31, 202369,043 221,462 37,417 143,371 
December 31, 202476,020 253,271 45,633 163,865 
December 31, 2025147,036 512,302 84,282 316,702 
Proved Undeveloped Reserves:
December 31, 202320,860 42,116 7,999 35,878 
December 31, 202417,543 39,353 7,907 32,009 
December 31, 202546,170 123,983 22,499 89,333 
(1)Includes total proved reserves of 219,259 MBOE, 94,019 MBOE, 91,417 MBOE and 81,895 MBOE as of December 31, 2025, 2024, 2023 and 2022, respectively, attributable to a non-controlling interest in the Operating Company.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2025, the Company’s total extensions and discoveries of 62,170 MBOE resulted primarily from the drilling of 1,497 new wells and from 1,071 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 18,570 MBOE were primarily attributable to negative revisions of (i) 11,481 MBOE associated with lower commodity prices, (ii) 4,722 MBOE due to PUD downgrades, and (iii) 2,367 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 201,291 MBOE resulted primarily from the Sitio Acquisition, the 2025 Drop Down, the Morita Ranches Acquisition and other acquisitions of certain mineral and royalty interests.

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Notes to Consolidated Financial Statements - (Continued)
During the year ended December 31, 2024, the Company’s total extensions and discoveries of 24,936 MBOE resulted primarily from the drilling of 1,170 new wells and from 447 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 2,894 MBOE were primarily attributable to negative revisions of (i) 6,539 MBOE associated with lower commodity prices, and (ii) 2,936 MBOE due primarily to PUD downgrades partially offset by positive revisions of 6,580 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 14,941 MBOE resulted primarily from the Tumbleweed Acquisitions and other acquisitions of certain mineral and royalty interests. Divestitures of 2,138 MBOE related primarily to non-core mineral and royalty interests.

During the year ended December 31, 2023, the Company’s total extensions and discoveries of 25,558 MBOE resulted primarily from the drilling of 904 new wells and from 179 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 138 MBOE consist of positive revisions of 5,688 MBOE primarily attributable to performance revisions which were largely offset by PUD downgrades of 5,548 MBOE. Total purchases of reserves in place of 18,977 MBOE resulted primarily from the GRP Acquisition and other acquisitions of certain mineral and royalty interests.

Proved Undeveloped Reserves

As of December 31, 2025, the Company’s PUD reserves totaled 46,170 MBbls of oil, 123,983 MMcf of natural gas and 22,499 MBbls of natural gas liquids, for a total of 89,333 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. The Company’s PUD reserves were from 1,653 horizontal wells, 61% of which are operated by Diamondback. Of the horizontal locations, 424 are Wolfcamp A wells, 415 are Wolfcamp B wells, 298 are Middle Spraberry/Jo Mill wells, 257 are Lower Spraberry wells, 82 are Bone Spring wells, 61 are Wolfcamp D wells, 47 are Dean wells, 46 are Barnett wells, 12 are Wolfcamp XY wells, eight are Wolfcamp C wells and three are Upper Spraberry wells.

The following table includes the changes in PUD reserves for 2025:

MBOE
Beginning proved undeveloped reserves at December 31, 2024
32,009 
Undeveloped reserves transferred to developed(11,848)
Revisions(5,643)
Purchases28,395 
Extensions and discoveries46,420 
Ending proved undeveloped reserves at December 31, 2025
89,333 

The increase in PUD reserves was primarily attributable to positive additions of 46,420 MBOE, primarily from 1,071 new horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate the Company’s acreage position and acquisitions of 28,395 MBOE. These increases in PUD reserves were partially offset by the conversion of 11,848 MBOE of PUD reserves into proved developed reserves and downward revisions of 5,643 MBOE primarily attributable to PUD downgrades of 4,421 MBOE.

All of the Company’s PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2025, none of the Company’s total proved reserves were classified as proved developed non-producing.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on SEC Prices. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future due to development and production of the reserves not occurring in the periods assumed, as well as actual prices realized and actual costs incurred varying significantly from those used in the estimates of proved reserves.

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Viper Energy, Inc.
Notes to Consolidated Financial Statements - (Continued)
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2025, 2024 and 2023:

December 31,
202520242023
(In millions)
Future cash inflows$15,377 $8,323 $8,494 
Future production taxes(1,080)(578)(594)
Future income tax expense(1,389)(749)(935)
Future net cash flows12,908 6,996 6,965 
10% discount to reflect timing of cash flows(6,261)(3,676)(3,778)
Standardized measure of discounted future net cash flows(1)
$6,647 $3,320 $3,187 
(1)Includes a 54%, 48% and 51% non-controlling interest in the Operating Company at December 31, 2025, 2024 and 2023, respectively.

The following table presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:

December 31,
202520242023
Oil (per Bbl)$64.80 $75.61 $77.93 
Natural gas (per Mcf)$1.31 $0.49 $1.54 
Natural gas liquids (per Bbl)$18.95 $20.62 $23.79 

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

Year Ended December 31,
202520242023
(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period$3,320 $3,187 $3,454 
Purchase of minerals in place3,738 355 474 
Divestiture of reserves— (51)— 
Sales of oil and natural gas, net of production costs(1,252)(793)(667)
Extensions and discoveries1,401 640 627 
Net changes in prices and production costs(279)(438)(1,405)
Revisions of previous quantity estimates(374)(85)3 
Net changes in income taxes(370)70 212 
Accretion of discount368 374 428 
Net changes in timing of production and other95 61 61 
Standardized measure of discounted future net cash flows at the end of the period$6,647 $3,320 $3,187 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2025, our disclosure controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. We are in the process of integrating the entities acquired in the Sitio Acquisition. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2025. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Sitio Acquisition on August 19, 2025. The total assets of Sitio represent approximately 32% of our consolidated total assets as of December 31, 2025, and the operating income of Sitio represent 12% of our total operating income for the year ended December 31, 2025.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Viper Energy, Inc.

Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Viper Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2025, and our report dated February 25, 2026 expressed an unqualified opinion on those financial statements.

Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of the entities acquired in the Sitio Acquisition, whose financial statements reflect total assets and operating income constituting 32 and 12 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025. As indicated in Management’s Report, the entities acquired in the Sitio Acquisition were acquired during 2025. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of the entities acquired in the Sitio Acquisition.

Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
February 25, 2026

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ITEM 9B. OTHER INFORMATION

None of our directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during our fiscal year ended December 31, 2025.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. We have also made the Code of Business Conduct and Ethics available on our website under the “Investors—Corporate Governance” section at https://www.viperenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11. EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2025.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as a part of this Form 10-K
1 and 2. Financial Statements and Financial Statement Schedules

The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules under Part II, Item 8. Financial Statements and Supplementary Data.

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.

3. Exhibits
Exhibit NumberDescription
2.1#
2.2#
2.3
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
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Exhibit NumberDescription
4.6
4.7
4.8
4.9
4.10
4.11
10.1
10.2+
10.3+
10.4+
10.5+
10.6+
10.7+
10.8
10.9+
10.10+
10.11+
10.12+
10.13+*#
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Exhibit NumberDescription
10.14+*#
10.15
19.1
19.2
21.1*
22.1*
23.1*
23.2*
31.1*
31.2*
32.1++
97.1*
99.1*
101
The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2025, formatted in Inline XBRL: (i) Consolidated Statements of Operations, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*
Filed herewith.
+
Management contract, compensatory plan or arrangement.
++
The certifications attached as Exhibit 32.1 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#Schedules (or similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VIPER ENERGY, INC.
Date:February 25, 2026
By:
VIPER ENERGY, INC.
By:
/s/ Kaes Van’t Hof
Name:
Kaes Van’t Hof
Title:Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SignatureTitleDate
/s/ Kaes Van’t Hof
Chief Executive Officer and DirectorFebruary 25, 2026
Kaes Van’t Hof
(Principal Executive Officer)
/s/ Teresa L. DickChief Financial OfficerFebruary 25, 2026
Teresa L. Dick(Principal Financial and Accounting Officer)
/s/ Steven E. WestChairman of the Board and DirectorFebruary 25, 2026
Steven E. West
/s/ Laurie H. Argo
DirectorFebruary 25, 2026
Laurie H. Argo
/s/ Spencer D. Armour III
DirectorFebruary 25, 2026
Spencer D. Armour III
/s/ Frank C. HuDirectorFebruary 25, 2026
Frank C. Hu
/s/ W. Wesley PerryDirectorFebruary 25, 2026
W. Wesley Perry
/s/ James L. RubinDirectorFebruary 25, 2026
James L. Rubin
/s/ Travis D. Stice
Director
February 25, 2026
Travis D. Stice

90
diff --git a/tests/issues/regression/test_issue_1382_combined_item_headings.py b/tests/issues/regression/test_issue_1382_combined_item_headings.py new file mode 100644 index 000000000..7b07db3eb --- /dev/null +++ b/tests/issues/regression/test_issue_1382_combined_item_headings.py @@ -0,0 +1,144 @@ +"""Regression: two items filed under one heading keep both items (GH #1382, #1383). + +GitHub Issues: https://github.com/dgunning/edgartools/issues/1382 + https://github.com/dgunning/edgartools/issues/1383 +Bead: edgartools-644g + +Energy filers combine items under one heading: "Items 1 and 2. Business and +Properties", "Items 1. and 2.", "Items 1. and 2.", "Items 7. and 7A.". +When that heading is the TOC link text, every TOC parser rejected it: the item +label regex needs "Item" followed by whitespace, so the plural's "s" failed it, +and the row was dropped. Part I then started at Item 1A, ``tenk.business`` was +None and the Business and Properties text sat in no section (Viper and Devon +regressed in 5.29.0 / 5.34.0; the #710 test injected ready-made keys and never +ran detection). Freeport's "Items 7. and 7A." kept Item 7 and lost 7A. + +On Talos the TOC puts "Items 1 and 2." and the link in separate cells, so Item 1 +survived, but Item 2 looked missing and the pattern pass admitted a bare +"Properties" sub-heading from inside Item 1 as a 1,311-character Item 2 (#1383). + +The fix reads a combined label as its first item and records both on +``Section.covered_items`` from the section's own heading; ``TenK`` resolves the +second item to that section and the pattern pass counts it as found. + +Offline (local fixtures, parsed end to end): + Viper Energy 10-K 0002074176-26-000010 tests/fixtures/html/vnom/10k/ + Cheniere Energy 10-K 0000003570-26-000005 tests/fixtures/html/lng/10k/ + Freeport-McMoRan 10-K 0000831259-25-000006 tests/fixtures/html/fcx/10k/ + Talos Energy 10-K 0001193125-26-067807 tests/fixtures/html/talo/10k/ +""" +import pathlib + +import pytest + +from edgar.company_reports.ten_k import TenK +from edgar.documents.utils.toc_analyzer import TOCAnalyzer + +FIXTURES = pathlib.Path(__file__).resolve().parents[2] / "fixtures" / "html" + +VIPER = FIXTURES / "vnom" / "10k" / "vnom-10-k-2026-02-25.html" +CHENIERE = FIXTURES / "lng" / "10k" / "lng-10-k-2026-02-26.html" +FREEPORT = FIXTURES / "fcx" / "10k" / "fcx-10-k-2025-02-14.html" +TALOS = FIXTURES / "talo" / "10k" / "talo-10-k-2026-02-25.html" + + +class FixtureFiling: + """The minimum surface TenK touches, backed by a local file.""" + + filing_date = None + form = "10-K" + company = "fixture" + + def __init__(self, path: pathlib.Path): + self._path = path + self.accession_number = path.stem + self.base_dir = str(path.parent) + + def html(self): + return self._path.read_text(encoding="utf-8", errors="replace") + + +@pytest.fixture(scope="module", params=[VIPER, CHENIERE, FREEPORT, TALOS], ids=lambda p: p.parts[-3]) +def tenk(request): + return TenK(FixtureFiling(request.param)) + + +@pytest.mark.fast +def test_the_fixtures_are_present(): + """Absent is not passing.""" + for path in (VIPER, CHENIERE, FREEPORT, TALOS): + assert path.exists(), path + + +@pytest.mark.fast +def test_combined_items_1_and_2_are_one_section(tenk): + part_i = [key for key in tenk.sections if key.startswith("part_i_")] + assert part_i[:2] == ["part_i_item_1", "part_i_item_1a"] + + section = tenk.sections["part_i_item_1"] + assert section.covered_items == ("1", "2") + assert section.detection_method == "toc" + + business = tenk.business + assert business + assert tenk["Item 2"] == business + assert "Item 2" in tenk.items + + +@pytest.mark.fast +def test_business_opens_on_the_combined_heading(): + """Each variant of the heading resolves, including '1.' and a nbsp after 'Items'.""" + assert TenK(FixtureFiling(CHENIERE)).business.startswith("ITEMS 1. AND 2.\xa0\xa0\xa0\xa0BUSINESS AND PROPERTIES") + assert TenK(FixtureFiling(FREEPORT)).business.startswith("Items 1. and 2. Business and Properties.") + # Viper's TOC link lands on a preamble paragraph ahead of its heading + viper = TenK(FixtureFiling(VIPER)).business + assert viper.startswith("On November 13, 2023, Viper Energy Partners LP converted") + assert "ITEMS 1 and 2. BUSINESS AND PROPERTIES" in viper[:3000] + + +@pytest.mark.fast +def test_combined_items_7_and_7a_resolve_7a(): + """Freeport's 'Items 7. and 7A.' used to leave Item 7A unreachable.""" + freeport = TenK(FixtureFiling(FREEPORT)) + section = freeport.sections["part_ii_item_7"] + assert section.covered_items == ("7", "7A") + assert "part_ii_item_7a" not in freeport.sections + assert freeport["Item 7A"] == freeport["Item 7"] + # A running header precedes the heading + assert freeport["Item 7A"].startswith( + "Table of Contents\n\nItems 7. and 7A.\xa0\xa0Management’s Discussion and Analysis") + + +@pytest.mark.fast +def test_properties_subheading_inside_item_1_is_not_a_second_item_2(): + """Talos: no 'properties' fragment claims Item 2 (GH #1383).""" + talos = TenK(FixtureFiling(TALOS)) + assert "properties" not in talos.sections + assert [key for key, s in talos.sections.items() if s.item == "2"] == [] + assert talos["Item 2"] == talos.business + + +@pytest.mark.fast +def test_ordinary_items_cover_nothing(): + """A one-item section records no combined coverage.""" + viper = TenK(FixtureFiling(VIPER)) + assert viper.sections["part_i_item_1a"].covered_items == () + assert viper.sections["part_ii_item_7"].covered_items == () + + +@pytest.mark.fast +@pytest.mark.parametrize("text,expected", [ + ("Items 1 and 2. Business and Properties", ("1", "2")), + ("Items 1. and 2. Business and Properties", ("1", "2")), + ("Items\xa01. and 2. Business and Properties", ("1", "2")), + ("ITEMS 1. AND 2.\xa0\xa0\xa0\xa0BUSINESS AND PROPERTIES", ("1", "2")), + ("Items 7. and 7A. Management's Discussion and Analysis", ("7", "7A")), + ("Items 1 & 2 Business", ("1", "2")), + # Not two items under one heading + ("Item 1. Business", None), + ("Items 10, 11 and 12", None), + ("Items 1, 1A and 2", None), + ("See Items 1 and 2", None), +]) +def test_combined_item_numbers(text, expected): + assert TOCAnalyzer.combined_item_numbers(text) == expected