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2025

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, 2025


☐			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: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)


Delaware			01-0562944
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer identification No.)

925 N. Eldridge Parkway, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading symbols	Name of each exchange on which registered
Common Stock, $.01 Par Value	COP	New York Stock Exchange
7% Debentures due 2029	CUSIP—718507BK1	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 (§ 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 checkmark 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 on June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $89.74, was $112.0 billion.

The registrant had 1,222,339,152 shares of common stock outstanding at January 31, 2026.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2026 (Part III)

Table of Contents


		Page
Commonly Used Abbreviations		1

Item
	Part I

1 and 2.	Business and Properties	2
	Corporate Structure	2
	Segment and Geographic Information	2
	Alaska	4
	Lower 48	6
	Canada	7
	Europe, Middle East and North Africa	8
	Asia Pacific	11

	Other	14
	Delivery Commitments	15
	Competition	15
	Human Capital Management	16
	General	17
1A.	Risk Factors	18
1B.	Unresolved Staff Comments	26
1C.	Cybersecurity	26
3.	Legal Proceedings	27
4.	Mine Safety Disclosures	28
	Information About our Executive Officers	28

	Part II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
6.	[Reserved]
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

7A.	Quantitative and Qualitative Disclosures About Market Risk	64
8.	Financial Statements and Supplementary Data	66
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	151
9A.	Controls and Procedures	151
9B.	Other Information	151
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	151

	Part III

10.	Directors, Executive Officers and Corporate Governance	152
11.	Executive Compensation	152
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	152
13.	Certain Relationships and Related Transactions, and Director Independence	152
14.	Principal Accounting Fees and Services	152

	Part IV

15.	Exhibits, Financial Statement Schedules	153
	Signatures	158


Commonly Used Abbreviations			Table of Contents

Commonly Used Abbreviations

The following industry-specific, accounting and other terms and abbreviations may be commonly used in this report.


Currencies		Accounting
$ or USD	U.S. dollar	ARO	asset retirement obligation
CAD	Canadian dollar	ASC	accounting standards codification
EUR	Euro	ASU	accounting standards update
GBP	British pound	DD&A	depreciation, depletion and
NOK	Norwegian kroner		amortization
		EPS	earnings per share
Units of Measurement		FASB	Financial Accounting Standards
BBL	barrel		Board
BCF	billion cubic feet	FIFO	first-in, first-out
BOE	barrels of oil equivalent	G&A	general and administrative
MBD	thousands of barrels per day	GAAP	generally accepted accounting
MCF	thousand cubic feet		principles
MM	million	LIFO	last-in, first-out
MMBOE	million barrels of oil equivalent	NPNS	normal purchase normal sale
MBOED	thousand barrels of oil equivalent	PP&E	properties, plants and equipment
	per day	VIE	variable interest entity
MMBOED	million barrels of oil equivalent
	per day	Miscellaneous
MMBTU	million British thermal units	CERCLA	Federal Comprehensive
MMCFD	million cubic feet per day		Environmental Response
MTPA	million tonnes per annum		Compensation and Liability Act
		EPA	Environmental Protection Agency
Industry		ESG	environmental, social and governance
BLM	Bureau of Land Management	EU	European Union
CBM	coalbed methane	FERC	Federal Energy Regulatory
E&P	exploration and production		Commission
FEED	front-end engineering and design	GHG	greenhouse gas
FID	final investment decision	HSE	health, safety and environment
FPS	floating production system	ICC	International Chamber of Commerce
FPSO	floating production, storage and	ICSID	World Bank’s International
	offloading		Centre for Settlement of
G&G	geological and geophysical		Investment Disputes
JOA	joint operating agreement	IRS	Internal Revenue Service
LNG	liquefied natural gas	OTC	over-the-counter
NGLs	natural gas liquids	NYSE	New York Stock Exchange
OPEC	Organization of Petroleum	SEC	U.S. Securities and Exchange
	Exporting Countries		Commission
PSC	production sharing contract	TSR	total shareholder return
PUDs	proved undeveloped reserves	U.K.	United Kingdom
SAGD	steam-assisted gravity drainage	U.S.	United States of America
WCS	Western Canadian Select	VROC	variable return of cash
WTI	West Texas Intermediate


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Part I

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and Properties, contain forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the headings “Risk Factors” beginning on page 18 and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 62.

Items 1 and 2. Business and Properties

Corporate Structure

ConocoPhillips is an independent E&P company headquartered in Houston, Texas with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; LNG developments; oil sands in Canada; and an inventory of global exploration prospects. On December 31, 2025, we employed approximately 9,900 people worldwide and had total assets of about $122 billion. Total company production for the year was 2,375 MBOED.

ConocoPhillips was incorporated in the state of Delaware in 2001 in connection with and in anticipation of the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002. In April 2012, ConocoPhillips completed the separation of the downstream business into an independent, publicly traded energy company, Phillips 66.

Segment and Geographic Information

25-0949-006-2026_Proxy_Global_Map_3Q25_c6 (002).jpg


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We manage our operations through five operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; and Asia Pacific. For operating segment and geographic information, see Note 22.

We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2025, our operations were producing in the U.S., Norway, Canada, Australia, Malaysia, Libya, China, Qatar and Equatorial Guinea.

The information listed below appears in the “Supplementary Data - Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

•Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.

•Net production of crude oil, NGLs, natural gas and bitumen.

•Average sales prices of crude oil, NGLs, natural gas and bitumen.

•Average production costs per BOE.

•Net wells completed, wells in progress and productive wells.

•Developed and undeveloped acreage.

The following table is a summary of the proved reserves information included in the “Supplementary Data - Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 84 percent of our proved reserves are in countries that belong to the Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six MCF of natural gas converts to one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the following summary reserves table.


	Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31	2025	2024	2023
Crude oil
Consolidated operations	3,321	3,406	3,032
Equity affiliates	103	108	89
Total crude oil	3,424	3,514	3,121

Natural gas liquids
Consolidated operations	1,166	1,147	892
Equity affiliates	59	62	48
Total natural gas liquids	1,225	1,209	940

Natural gas
Consolidated operations	1,617	1,629	1,408
Equity affiliates	969	977	879
Total natural gas	2,586	2,606	2,287

Bitumen
Consolidated operations	402	483	410
Total bitumen	402	483	410

Total consolidated operations	6,506	6,665	5,742
Total equity affiliates	1,131	1,147	1,016
Total company	7,637	7,812	6,758


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Alaska

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs. We are the largest crude oil producer in Alaska and have major ownership interests in the Prudhoe Bay, Kuparuk and Western North Slope asset areas. Additionally, we are one of Alaska’s largest owners of state, federal and fee exploration leases, with approximately one million net undeveloped acres at year-end 2025. Alaska operations contributed 12 percent of our consolidated liquids production and one percent of our consolidated natural gas production.


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production

Greater Prudhoe Area	36.5	%	Hilcorp	63	15	40	85
Greater Kuparuk Area	94.2-99.8		ConocoPhillips	75	—	—	75
Western North Slope	100.0		ConocoPhillips	39	—	1	39
Total Alaska				177	15	41	199

Willow Project

The Bear Tooth Unit in the Western North Slope includes the Willow Project (Willow). In December 2023, we announced Willow FID. The project will consist of three drill sites, an operations center and camp, and a processing facility. In 2025, the project completed the peak construction season, which included gravel and pipeline construction and operations center hookup and installation, and is expected to achieve near 50 percent project completion this winter season. Additionally, fabrication of the processing facility is on schedule for transport to the North Slope in 2027. First oil is anticipated in early 2029.

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Unit, which consists of the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest conventional oil field in North America, is the site of a large waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation. Field installations include seven production facilities, two gas plants, two seawater plants and a central power station. In 2025, on average, there were three rigs drilling throughout the year.

Greater Kuparuk Area

The Greater Kuparuk Area includes the Kuparuk River Unit, which consists of the Kuparuk Field and six satellite fields. Field installations include three central production facilities which separate oil, natural gas and water, and a seawater treatment plant. In 2025, on average, we operated two drilling rigs and one workover rig. The Nuna project, which targets the Moraine reservoir, was sanctioned in 2023 and achieved first oil in the fourth quarter of 2024. We drilled additional wells in 2025 and plan to continue drilling activity through 2027. The Coyote reservoir, discovered in 2021, progressed to development in 2023, with additional wells drilled in 2024 and 2025, and a pad expansion project planned for 2026.


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Western North Slope

The Western North Slope includes the Bear Tooth Unit (as highlighted above), the Colville River Unit and the Greater Mooses Tooth Unit. These units also leverage shared regional infrastructure, which underpins base operations and facilitates continued development across the Western North Slope. In 2025, we operated one part-time drilling rig in the Colville River Unit.

The Colville River Unit includes the Alpine Field and four satellite fields. Field installations include one central production facility, which separates oil, natural gas and water.

The Greater Mooses Tooth Unit is the first unit established entirely within the National Petroleum Reserve Alaska (NPR-A). The unit was constructed in two phases: Greater Mooses Tooth #1 (GMT1) and Greater Mooses Tooth #2 (GMT2).

Exploration

We are continuing our exploration activities in the NPR-A with a planned four-well drilling program this 2026 winter season.

Transportation

We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile pipeline that is part of the Trans-Alaska Pipeline System (TAPS). We have a 29.5 percent ownership interest in TAPS, and also have ownership interests in, and operate the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

We manage the marine transportation of our North Slope production using five company-owned, double-hulled tankers, and charter third-party vessels, as necessary. The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.


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Lower 48

The Lower 48 segment consists of operations located in the 48 contiguous U.S. states, with a portfolio mainly consisting of low cost of supply, short cycle time, resource-rich unconventional plays and commercial operations. The majority of our acreage is unconventional. Based on 2025 production volumes, the Lower 48 is our largest segment and contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.


	2025
	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Delaware Basin	321	171	1,011	661
Eagle Ford	202	102	516	390
Bakken	114	50	241	204
Midland Basin	103	48	251	192
Other	9	11	100	37
Total Lower 48	749	382	2,119	1,484

Delaware Basin

We hold approximately 782,000 net acres in the Delaware Basin, spanning west Texas through southeast New Mexico. Current development activity targets prospects in the Avalon, Bone Springs, Wolfcamp and Woodford formations while balancing leasehold obligations and permit terms. We operated ten rigs and three frac crews on average during 2025, resulting in 176 operated wells drilled and 161 operated wells brought online.

Eagle Ford

We hold approximately 489,000 net acres in the Eagle Ford, located in south Texas. The current focus is on full-field development, using customized well spacing and stacking patterns adapted through reservoir analysis. We operated seven rigs and three frac crews on average during 2025, resulting in 251 operated wells drilled and 264 operated wells brought online.

Bakken

We hold approximately 799,000 net acres in the Williston Basin, located in North Dakota and eastern Montana. The primary producing zones are the Middle Bakken and Three Forks formations. We operated three rigs and one frac crew on average during 2025, resulting in 72 operated wells drilled and 98 operated wells brought online.

Midland Basin

We hold approximately 416,000 net acres in the Midland Basin, located in west Texas. The current development strategy is focused on full-field development utilizing multi-well pad projects targeting Barnett, Spraberry and Wolfcamp reservoir targets. We operated three rigs and one frac crew on average during 2025, resulting in 86 operated wells drilled and 94 operated wells brought online.

Partner-Operated

We participate in partner-operated wells when they align with our investment decision criteria and development strategies. In 2025, we participated in partner-operated wells with varying working interests across our Lower 48 portfolio.

Facilities

We operate and own, with varying interests, centralized processing facilities in Texas and New Mexico in support of our Delaware, Eagle Ford and Midland assets.


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Canada

Our Canadian operations consist of the Surmont oil sands development in Alberta, the liquids-rich Montney unconventional play in British Columbia and commercial operations. In 2025, operations in Canada contributed nine percent of our consolidated liquids production and five percent of our consolidated natural gas production.


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Bitumen MBD	Total MBOED
Average Daily Net Production
Surmont	100.0	%	ConocoPhillips	—	—	—	133	133
Montney	100.0		ConocoPhillips	17	6	125	—	44
Total Canada				17	6	125	133	177

Surmont

The Surmont oil sands leases are located south of Fort McMurray, Alberta. Surmont is a 100 percent working interest asset that offers sustained, long-life production. We are focused on keeping facilities full, structurally lowering costs, reducing GHG intensity and optimizing asset performance. In the third quarter of 2025, we commenced drilling of Pad 104W-B and in the fourth quarter of 2025, we achieved first production from Pad 104W-A.

Our bitumen resources in Canada are produced via SAGD, an enhanced thermal oil recovery method where steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing. Operations include two central processing facilities for treatment and blending of bitumen, and a diluent recovery unit. These facilities have allowed the asset to lower blend ratio and diluent supply costs, while gaining protection from diluent supply disruptions and increased market access for our product. At December 31, 2025, we held approximately 684,000 net acres of land in the Athabasca Region of northeastern Alberta.

Montney

The Montney is a liquids-rich unconventional play located in northeastern British Columbia. At December 31, 2025, we held approximately 297,000 unconventional net acres of land in the Montney. In 2025, we operated two rigs and one frac crew resulting in 31 wells drilled and 23 operated wells brought online.


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Europe, Middle East and North Africa

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 2025, operations in Europe, Middle East and North Africa contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.

Norway


			2025
	Interest	Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Greater Ekofisk Area	28.3 - 35.1%	ConocoPhillips	38	2	83	54
Heidrun	24.0	Equinor	9	—	35	15
Troll	1.6	Equinor	1	—	66	12
Aasta Hansteen	10.0	Equinor	—	—	66	11
Alvheim	20.0	Equinor	7	—	16	9
Visund	9.1	Aker BP	1	1	44	9
Other	Various	Equinor	7	—	20	11
Total Norway			63	3	330	121

Greater Ekofisk Area

The Greater Ekofisk Area is located offshore Stavanger, Norway, in the North Sea, and is comprised of five producing fields. Crude oil is exported to our operated terminal located at Teesside, U.K., and the natural gas is exported to Emden, Germany.

Partner-Operated

We participate in various partner-operated fields located either in the Norwegian Sea or northern part of the North Sea. Crude oil and natural gas are produced and transported to various processing plants and terminals, primarily in Norway and the U.K.

Exploration

In 2025, we drilled the second appraisal well in the 2020 Slagugle discovery on PL891. The well encountered hydrocarbons and a significant data acquisition program was completed. The collected data will be analyzed to evaluate a possible future development. We also participated in the Bounty Updip exploration well on PL886 in the Norwegian Sea. The well was expensed as a dry hole. Additionally, we participated in the Othello South exploration well in the Heidrun area of the Norwegian Sea, which encountered hydrocarbons. In 2025, we were awarded two new exploration licenses in the North Sea, PL1248 and PL1259, and one acreage addition, PL044D.


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Transportation

We have a 35.1 percent ownership interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and NGLs processing facility in Teesside, U.K.

Facilities

We operate and have a 40.25 percent ownership interest in a crude oil stabilization and NGLs processing facility at Teesside, U.K. to support our Norway operations.

Qatar


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
QatarEnergy LNG N(3)	30.0	%	QatarEnergy LNG	12	8	373	82

QatarEnergy LNG N(3) (N3), is an integrated development jointly owned by QatarEnergy (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). N3 consists of upstream natural gas production facilities, which produce approximately 1.4 gross BCF per day of natural gas from Qatar’s North Field over a 25-year life, in addition to a 7.8 million gross tonnes per year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally, while liquids are sold into the domestic market or marketed internationally through QatarEnergy Marketing.

N3 executed the development of the onshore and offshore assets as a single integrated development with QatarEnergy LNG N(4) (N4), a joint venture between QatarEnergy and Shell plc. This included the joint development of offshore facilities situated in a common offshore block in Qatar's North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the N3 and N4 joint ventures. Production from the LNG trains and associated facilities is mutualized between the two joint ventures.

We have a 25 percent interest in both QatarEnergy LNG NFE (4) (NFE4) and QatarEnergy LNG NFS (3) (NFS3) joint ventures, which are participating in the North Field East (NFE) and North Field South (NFS) LNG projects, respectively. See Note 3 and Note 4.

Libya


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Waha Concession	20.4	%	Waha Oil Co.	60	—	32	65

The Waha Concession is made up of multiple concessions and encompasses approximately 13 million acres onshore in the Sirte Basin for exploration and production activity. Oil is transported by pipeline to the Es Sider terminal for export. Natural gas is transported and sold domestically. Current production comes from 13 existing fields within the Waha Concession.

In January 2026, we signed an agreement with the Libyan Ministry of Oil and Gas and the National Oil Corporation of Libya to extend the Waha Concession up to December 31, 2050, with new fiscal terms, subject to normal regulatory approvals.


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Equatorial Guinea


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Alba Unit	64.2	%	ConocoPhillips	8	5	149	38

We have varying stages of oil and gas exploration, development and production activities in Equatorial Guinea. We operate in both the Alba and Block D PSCs that form the Alba Unit located offshore Equatorial Guinea.

Gas Processing

The following facilities located on Bioko Island allow us to further monetize natural gas production from the Alba Unit and are accounted for as equity method investments and are reflected in the "Equity in earnings of affiliates" line of our consolidated income statement.

We own a 52.2 percent interest in the Alba Plant LLC, our joint venture with Chevron Corporation (27.8 percent) and Sociedad Nacional de Gas de Guinea Ecuatorial (SONAGAS) (20 percent), which operates an onshore liquified petroleum gas (LPG) processing plant. Alba Plant LLC processes Alba Unit natural gas under a fixed-rate long-term contract. The LPG processing plant extracts condensate and LPG from the natural gas stream and sells it at market prices, with our share of the revenue reflected in the "Equity in earnings of affiliates" line of our consolidated income statement. Processed natural gas is delivered to Equatorial Guinea LNG Holdings Limited (EG LNG) for liquefaction and storage. We market our share of LNG to third parties indexed at global LNG prices.

We own a 56 percent interest in EG LNG, our joint venture with SONAGAS (37.9 percent) and Marubeni Gas Development UK Limited (6.1 percent), which operates a 3.7 MTPA LNG production facility. In January 2024, we began a five-year LNG sales agreement for a portion of our equity gas from the Alba Unit, providing us with additional exposure to the European LNG market.

We own a 45 percent interest in Atlantic Methanol Production Company LLC (AMPCO), our joint venture with Chevron Corporation (45 percent) and SONAGAS (10 percent), which operates a methanol plant. The plant is currently offline.

Additionally, Alba Plant LLC and EG LNG process third-party gas from the Alen Field under a combination of tolling fee and profit-sharing arrangements which are reflected in the "Equity in earnings of affiliates" line of our consolidated income statement.


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Asia Pacific

The Asia Pacific segment has exploration and production operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. In 2025, operations in the Asia Pacific segment contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Australia


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Australia Pacific LNG	47.5	%	ConocoPhillips/Origin Energy	—	—	833	139

Australia Pacific LNG Pty Ltd. (APLNG), our joint venture with Origin Energy Limited (Origin) and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for export. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.

We operate two fully subscribed 4.5 MTPA LNG trains. Approximately 3,500 net wells are ultimately expected to supply both the LNG sales contracts and domestic gas market. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities and an export pipeline connecting the gas fields to the LNG facilities. The LNG is being sold to Sinopec under a 20-year sales agreement for 7.6 MTPA of LNG, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately one MTPA of LNG.

For additional information, see Note 4 and Note 8.

Exploration

We own a 51 percent working interest in both Exploration Permit (T/49P) and (VIC/P79) located in the Otway Basin, Australia, after transferring 29 percent working interest to Korea National Oil Corporation in 2025. From November 2025 to early 2026, we drilled two exploration wells in VIC/P79. The first well, Essington-1, encountered hydrocarbons and continues to be evaluated. The second well, Charlemont-1, found no commercial hydrocarbons and was expensed as a dry hole in the fourth quarter of 2025.


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China


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Penglai	49.0	%	CNOOC	34	—	—	34

Penglai

The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are being developed in stages from large offshore platforms and a FPSO. Most of the crude oil produced from the block is sold to the domestic market in China, with the remainder exported to international markets.

Phase 4B consists of two wellhead platforms. First production was achieved in the fourth quarter of 2023. This project could include up to 144 new wells, 95 of which have been completed and brought online as of December 2025.

Phase 5 consists of two new wellhead platforms and four wellhead platform expansions. First production was achieved in the fourth quarter of 2024. This project could include up to 91 new wells, 25 of which have been completed and brought online as of December 2025.

Malaysia


				2025
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Gumusut	29.5	%	Shell	14	—	—	14
Malikai	35.0		Shell	1	—	63	12
Kebabangan (KBB)	30.0		ConocoPhillips	9	—	—	9
Siakap North-Petai	21.0		PTTEP	1	—	—	1
Total Malaysia				25	—	63	36

We have varying stages of exploration, development and production activities in Malaysia, with working interests in four PSCs, and as of January 2025, sole operatorship at the Kebabangan Cluster (KBBC), our first operated producing asset in

Malaysia. These PSCs are located in waters off the eastern Malaysian state of Sabah: Block G, Block J, KBBC and the Ubah Cluster.

Block J

Gumusut

We own a 29.5 percent working interest in the unitized Gumusut Field. Development associated with Gumusut Phase 4, a four-well program targeting the Brunei acreage of the unitized Gumusut Field that straddles Malaysia and Brunei waters, completed drilling in 2024 with first production achieved in early 2025. The unitized Gumusut Field is operated on a FPS with oil evacuation via a pipeline to the Sabah Oil and Gas Terminal (SOGT) for tanker liftings.

KBBC

We own a 30 percent working interest in the KBB, Kamunsu East and Kamunsu East Upthrown Canyon gas and condensate fields.

KBB

Gas is transported from the KBB platform via pipeline for sale to the domestic gas market. Since 2019, KBB tied-in to a nearby third-party floating LNG vessel, which provided additional gas offtake capacity.


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Block G

Malikai

We own a 35 percent working interest in Malikai. Malikai Phase 2 development first oil was achieved in February 2021. Malikai operates on a tension leg platform and pipes oil to the KBB platform for processing. Oil evacuation is via pipeline to SOGT for tanker liftings.

Siakap North-Petai

We own a 21 percent working interest in the unitized Siakap North-Petai (SNP) oil field. First oil from SNP Phase 2 was achieved in November 2021. The subsea system in the SNP oil field is tied back to a FPSO operated by PTTEP.

Exploration

We operate one exploration PSC with a 35 percent working interest in the Ubah Cluster. Located off the coast of Sabah, offshore Malaysia and near the KBBC, the Ubah Cluster encompasses 11 thousand net acres. We continue to evaluate the block and are using information from seismic to optimize future plans.

At the beginning of 2025, we operated two additional exploration PSCs off the coast of Sarawak, offshore Malaysia, Block SK304 encompassing 1.8 million net acres and Block WL4-00 encompassing 0.3 million net acres. We relinquished both blocks, effective in the first and fourth quarter of 2025, respectively.


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Other

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which includes natural gas, crude oil, bitumen, NGLs, LNG and power. Marketing activities are performed through offices in the U.S., Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase and sell third-party commodity volumes to better position the company to satisfy customer demand while fully utilizing transportation and storage capacity.

Crude Oil, Bitumen and NGLs

Our crude oil, bitumen and NGL revenues are derived from production in the U.S., Canada, Asia, Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Natural Gas

Our natural gas production, along with third-party purchased gas, is primarily marketed in the U.S., Canada and Europe. Our natural gas is sold to a diverse client portfolio, which includes local distribution companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and interruptible transportation agreements to major market hubs.

LNG

We have investments in LNG facilities which are supplied with equity gas production in Australia, Qatar and Equatorial Guinea. We also have a 30 percent direct equity holding in Port Arthur Liquefaction Holdings, LLC (PALNG) for Phase 1 of the Port Arthur LNG project, which is scheduled to start up in 2027. Additionally, as part of our LNG strategy to build a dynamic portfolio and expand our footprint across the value chain, we have various commercial LNG offtake agreements in North America totaling 10.2 MTPA with offtake commencing between 2026-2031. Furthermore, we currently have a total regasification capacity in Europe of approximately 6.7 MTPA. We continue to progress discussions across all major LNG producing and consuming regions and markets to further add high-quality positions to our portfolio. See Note 3.


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Emergency Response Partnerships

Emergency response partnerships are vital for effective disaster management. By uniting government agencies, non-profits, private companies and community groups, these partnerships enhance preparedness, response and recovery efforts. We maintain memberships in several global response and containment partnerships as a key element of our emergency response preparedness program, complementing our internal response resources.

Oil Spill Response Organizations (OSROs)

We maintain memberships in several OSROs, many of which are not-for-profit cooperatives owned by member companies. We may actively participate in these organizations as members of the board of directors, steering committees, work groups or other supporting roles. In North America, our primary OSROs include the Marine Spill Response Corporation for the continental U.S. and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince William Sound, respectively. Internationally, we maintain memberships in various OSROs, including Oil Spill Response Limited, the Norwegian Clean Seas Association for Operating Companies, the Australian Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.

Technology

We have several technology programs that improve our ability to develop unconventional reservoirs, increase recovery from our legacy fields, improve the efficiency of our exploration program, produce heavy oil economically with lower emissions and implement sustainability measures.

We are the second-largest LNG liquefaction technology provider globally based on total global installed production capacity. Our Optimized Cascade® LNG liquefaction technology has been licensed for use in 28 LNG trains around the world, with FEED studies ongoing for additional trains.

We continue to evaluate opportunities to support our operational emissions reduction objectives and evaluate lower carbon opportunities for future competitive investment with the same discipline we follow in our traditional business investment and capital allocation process.

Delivery Commitments

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 9 MTPA of LNG, 820 billion cubic feet of natural gas and 175 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2042. We have a variety of options to fulfill our delivery commitments including third-party purchases, as supported by our gas management and power supply agreements, LNG sales agreements, proved developed reserves and PUDs. See the disclosure on “Proved Undeveloped Reserves” in the “Supplementary Data - Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of PUDs.

Competition

ConocoPhillips is one of the world’s leading E&P companies based on both production and reserves, with a globally diversified asset portfolio. We compete with private, public and state-owned companies in all facets of the E&P business. Some of our competitors are larger and have greater resources. Each of our segments is highly competitive, with no single competitor, or small group of competitors, dominating.

We compete with numerous other companies in the industry, including state-owned companies, to locate and obtain new sources of supply and to produce oil, bitumen, LNG, NGLs and natural gas in an efficient, cost-effective manner. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; equipment and personnel; economic analysis in connection with portfolio management and safely operating oil and gas producing properties.


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Human Capital Management

At ConocoPhillips, our strategy, performance, culture and reputation are fueled by our workforce. Attracting, retaining and developing a world-class workforce is a competitive imperative within our complex industry. Our human capital management (HCM) approach is based on our core SPIRIT Values – Safety, People, Integrity, Responsibility, Innovation and Teamwork – which set the tone for our interactions with all stakeholders. We believe a safe organization is a successful organization and we prioritize personal and process safety across the company.

Our Executive Leadership Team (ELT) and Board of Directors help to set our HCM strategy and drive accountability for meaningful progress. Our HCM programs are managed by our human resources function with support from business leaders across the company and are regularly reviewed by the Board of Directors. Our efforts are built around three pillars: a compelling culture, attracting a world-class workforce and valuing our people.

At year-end 2025, we had approximately 9,900 employees in 14 countries. A table of 2025 employees by country is shown below:


2025 Employees by Country	Percent of Total
U.S.	62	%
Norway	16
Canada	8

Equatorial Guinea	4
Malaysia	3

Other Global Locations	7
Total	100	%

A Compelling Culture

How we do our work is what sets us apart and drives our performance. As our industry evolves, we need a workforce equipped to address new opportunities and challenges. Our success depends on our people. Effectively engaging, developing and rewarding our employees is a priority for us. Together, we deliver strong performance while embracing our core cultural attributes.

Health, Safety and Environment

Our HSE organization sets expectations and provides tools and assurance to our workforce to promote and achieve HSE excellence. We manage and assure ConocoPhillips HSE policies, standards and practices, to help ensure business activities are consistently safe, healthy and conducted in an environmentally and socially responsible manner across the globe. Each business unit manages its local operational risks with particular attention to process safety, occupational safety and environmental and emergency preparedness risks. Objectives, targets and deadlines are set and tracked annually to drive strong HSE performance. Progress is tracked and reported to our ELT and the Board of Directors. Corporate HSE audits are conducted on business units and staff groups to ensure conformance with ConocoPhillips HSE policies, standards and practices. If improvement actions are identified, they are tracked to completion.

We continuously look for ways to operate more safely, efficiently and responsibly. We focus on reducing human error by emphasizing interaction among people, equipment and work processes. We believe our HSE policies such as Life Saving Rules, Process Safety Fundamentals, safety procedures and our stop work policy can reduce the likelihood and severity of unexpected incidents. We conduct thorough investigations of all serious incidents to understand the root cause and share lessons learned globally to improve our facility designs, procedures, training and maintenance programs. It is important that we drive an HSE culture of continuous learning and improvement, refine our existing HSE processes and tools and enhance our commitment to safe, efficient and responsible operations.

Attracting a World-Class Workforce

Our continued success requires a skilled global workforce. Our SPIRIT Values help to cultivate an inclusive environment where everyone can contribute, promoting innovation and leading to better business outcomes. This helps us attract a workforce equipped to address new opportunities and challenges that we face in a complex industry. We recruit experienced hires to help us sustain a broad range of expertise and partner with universities and organizations to create a pipeline of early-career talent. We strive to ensure fair and consistent practices in our recruitment process and conduct talent assessments to meet our business needs.


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Valuing our People

Employee Engagement and Development

We engage and develop our workforce through on-the-job learning, formal training, ongoing feedback, coaching and mentoring. Additionally, we use a performance management program focused on merit, objectivity, credibility and transparency. The program includes broad stakeholder feedback, real-time monetary and non-monetary recognition and a formal "how" rating to assess behavior to ensure they align with our SPIRIT Values.

Skills-based Talent Management Teams (TMTs) guide employee development and career progression, help identify workforce planning needs and assess the availability of critical skill sets. Succession planning is a top priority for management and the Board of Directors to ensure talent readiness and availability for leadership roles.

We measure and assess employee satisfaction and engagement through periodic employee engagement surveys. Our leaders review survey feedback to guide priorities and goals.

Compensation, Benefits and Well-Being

We offer competitive, performance-based compensation packages and have global, equitable pay practices. Our compensation programs generally include base pay, the annual Variable Cash Incentive Program (VCIP) and, for eligible employees, the Restricted Stock Unit (RSU) program. Our retirement and savings plans support employees' financial futures and are competitive within local markets.

We routinely benchmark our global compensation and benefits programs to ensure they are competitive and meet the needs of our employees. We provide flexible work schedules and competitive time off, including parental leave in many locations. We also provide coverage for disability support, elder care and childcare, including onsite childcare, where access locally is a challenge.

General

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page 53 under the caption "Environmental" and beginning on page 55 under the caption “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2025 and those expected for 2026 and 2027.

Website Access to SEC Reports

Our internet website address is www.conocophillips.com. Information contained on our internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.


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Item 1A. Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any of these risks or other risks that are yet unknown or currently considered immaterial were to occur, our business, operating results and financial condition, as well as the value of an investment in our common stock, could be materially and adversely affected.

Risks Related to Our Industry

Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to the effects of volatile commodity prices or prolonged periods of low commodity prices.

Among the most significant factors impacting our revenues, operating results and future rate of growth are the sales prices for crude oil, bitumen, LNG, natural gas and NGLs. These prices are tied to market prices that can fluctuate widely due to factors beyond our control. For example, over the course of 2025, WTI crude oil prices ranged from a high of $80 per barrel in January to a low of $55 per barrel in December. Given the volatility in the drivers of commodity prices and our associated realizations, the worldwide political and economic environment, including potential economic slowdowns or recessions, unexpected shocks to supply and demand, or increased uncertainty generated by armed hostilities and geopolitical tension and escalations in various oil-producing regions around the globe, prices for crude oil, bitumen, LNG, natural gas and NGLs may continue to be volatile.

Prolonged periods of low commodity prices could have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock and the amount of shares we elect to acquire as part of our share repurchase program and the timing of such repurchases.

Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the reduction in our existing proved reserve levels as we continue production from upstream fields. Prolonged depressed prices may affect strategic decisions related to our operations, including decisions to reduce capital investments or curtail operated production.

Significant reductions in crude oil, bitumen, LNG, natural gas and NGLs prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production rates at this time, our results of operations could be adversely affected as a result.

If we do not successfully develop resources, the scope of our business will decline, and our financial condition and results of operations may be adversely affected.

As we produce crude oil, bitumen, natural gas and NGLs from our existing portfolio, the amount of our remaining reserves declines. If we do not successfully replace the resources we produce with good prospects for future organic development or through acquisitions, our business will decline. In addition, our ability to successfully develop our reserves depends on our achievement of a number of operational and strategic objectives, some aspects of which are beyond our control, including navigating political and regulatory challenges to obtain and renew rights to develop and produce hydrocarbons; reservoir optimization; bringing long-lead time, capital intensive projects to completion on budget and on schedule; and efficiently and profitably operating mature properties. If we are not successful in developing the resources in our portfolio, our financial condition and results of operations may be adversely affected.

The exploration and production of oil and gas is a highly competitive industry.

The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including locating, acquiring and developing new sources of supply and producing crude oil, bitumen, natural gas and NGLs in an efficient, cost-effective manner. In addition, we anticipate the oil and gas industry will face additional competition from alternative fuels. We must also compete for the materials, equipment, services, employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business. If we are not successful in any facet of this competition, our financial condition and results of operations may be adversely affected.


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Our ability to successfully execute on our plans to reduce operational GHG emissions intensity is subject to a number of risks and uncertainties and such reductions may be costly and challenging to achieve.

Our framework for managing climate-related business risk is set out in our Climate-related Risk Strategy, which describes our strategic flexibility, approach to reducing Scope 1 and 2 emissions intensity, technology choices and engagement efforts. Among other things, we have set near- and medium-term GHG intensity reduction targets, as well as targets around flaring and methane. Our ability to achieve the stated targets, goals and ambitions within the Climate-related Risk Strategy's framework is subject to a number of risks and uncertainties beyond our control, including government policies and markets, acceptance of carbon capture technologies, development of markets and potential permitting and regulatory changes, all of which may impair our ability to execute on current or future plans. In addition, the pace of development of effective emissions measurement and abatement technologies, and the actual pace of deployment may be inadequate, or the technologies actually developed may be insufficient to allow us to achieve our stated targets, goals and ambitions.

Furthermore, executing our Climate-related Risk Strategy could be costly, is likely to encounter unforeseen obstacles, will proceed at varying paces and may be accomplished in a manner that we cannot predict at this time. We expect to be required to purchase emission credits and/or offsets in the future. There may be an insufficient supply of offsets, and we could incur increasingly greater expenses related to our purchase of such offsets. Even if we are able to acquire an adequate amount of such offsets at satisfactory prices, investors, regulators or other third parties may not perceive this practice as an acceptable means of achieving our operational emission reduction targets. As advanced technologies are developed to accurately measure emissions, we may be required to revise our emissions estimates and reduction goals or otherwise revise aspects of our Climate-related Risk Strategy. We may be adversely affected and potentially need to reduce economic end-of-field life of certain assets and impair associated net book value due to the emissions intensity of some of our assets. Even if we meet our goals, our efforts may be characterized as insufficient.

We continue to evaluate low carbon opportunities for potential future investment in support of our operational emission reduction targets. Such potential investments may expose us to numerous financial, legal, operational, reputational and other risks and may not ultimately contribute materially to operational emissions reductions. The success of any such investment will depend in part upon the cooperation of government agencies, the support of stakeholders, the development of relevant markets for low carbon fuels, our ability to research and forecast potential investments, willingness of industry partners to collaborate and our ability to apply our existing strengths and expertise to new technologies, projects and markets.

Estimates of crude oil, bitumen, natural gas and NGL reserves are imprecise and may be subject to revision, and any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and NGL reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report represents management’s best estimates based on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured, and the estimates and underlying assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and commodity prices. For more information on estimates used, see the "Critical Accounting Estimates" section of Management's Discussion and Analysis of Financial Condition and Results of Operations.


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Our business may be adversely affected by price controls; government-imposed limitations on production or exports of crude oil, bitumen, LNG, natural gas and NGLs; or the unavailability of adequate gathering, processing, compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen, natural gas and NGLs.

As discussed herein, our operations are subject to extensive governmental regulations across numerous jurisdictions. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and NGLs wells below actual production capacity. Similarly, in response to increased domestic energy costs, circumstances determined to be in the economic or other interest of the country, or a declared national emergency, governments could restrict the export or import of our products which would adversely impact our business. For example, in January 2024, in response to concerns from environmental groups, the U.S. announced a temporary pause on new authorizations of certain LNG exports. The pause was subsequently lifted in January 2025. This pause and other difficulties in the regulatory approval processes may have an extended adverse impact on our global LNG business. Furthermore, because legal requirements are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our business may be enacted or become applicable to us.

Our ability to sell and deliver the crude oil, bitumen, LNG, natural gas and NGLs that we produce also depends on the availability, proximity and capacity of gathering, processing, compression, transportation and pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, LNG, natural gas and NGLs for transport. The facilities, equipment and diluents we rely on may be temporarily unavailable to us due to market conditions, extreme weather events, permitting delays and other regulatory matters, mechanical reasons or other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells, and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil, bitumen, LNG, natural gas and NGLs for sale; we may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs, or we may not be able to meet all the objectives in our Climate-related Risk Strategy, such as reducing routine flaring.

Our ability to manage risk or influence outcomes in joint ventures may be constrained.

We conduct many of our operations through joint ventures in which another joint venture partner is the operator or we may not have majority control. In these cases, the economic, business, or legal interests or goals of the operator or the voting majority may be inconsistent with ours, and we may not be able to influence the decision making or outcomes to align with our interests or goals. Failure by an operator or a voting majority, with whom we have a joint venture interest, to adequately manage the risks associated with any operations could have an adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

Our operations are subject to hazards and risks that require significant and continuous oversight.

Our operations are subject to a variety of hazards and risks that require significant and continuous oversight, such as the monitoring, prevention or mitigation of or protection from explosions; fires; product spills; severe weather; geological events; global health crises, such as epidemics and pandemics; labor disputes; geopolitical tensions and escalations; armed hostilities; terrorist or piracy attacks; sabotage; civil unrest or cyberattacks. Our operations are subject to additional hazards concerning exposure to and potential release of pollutants and toxic substances, as well as other environmental hazards and risks. For example, offshore activities may pose incrementally greater technological challenges, operating risks and potential for adverse consequences from operational failures because of complex subsurface conditions such as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation. Our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to efficiently restore or replace affected operational components and capacity. Countermeasures to address global health crises, epidemics or pandemics may result in reduced demand for our products; disruptions to our supply chain, the global economy or financial or commodity markets; disruptions in our contractual arrangements with our service providers, suppliers and other counterparties; failures by our suppliers, contract manufacturers, contractors, joint venture partners and external business partners to meet their obligations to us; reduced workforce productivity; and voluntary or involuntary curtailments. Further, our insurance may not be adequate to compensate us for all resulting losses described above, and the cost to obtain adequate coverage may increase for us in the future or may not be available.


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In addition, although we design and operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the earth's climate, such as more severe or frequent weather conditions in the markets where we operate or the areas where our assets reside, we could incur increased expenses, our operations and supply chain could be adversely impacted and demand for our products could fall.

Any of these factors, or other cascading effects of such factors, could materially increase our costs; negatively impact our revenues or ability to implement and advance our Climate-related Risk Strategy; and damage our financial condition, results of operations, cash flows and liquidity position. The full extent and duration of any such impacts cannot be predicted at this time because of the lack of certainty surrounding their sources, causes and outcomes.

Legal and Regulatory Risks

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations.

Our business is subject to numerous laws and regulations relating to the protection of the environment, which are expected to continue to have an increasing impact on our operations. For a description of the most significant of these environmental laws and regulations, see the “Contingencies—Environmental”, “—Climate Change” and "—Company Response to Climate-Related Risks" sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

•Permits required in connection with exploration, drilling, production and other activities, including those issued by national, subnational and local authorities;

•The discharge of pollutants into the environment;

•Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions, including methane and carbon dioxide;

•Carbon taxes;

•The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes;

•The dismantlement, abandonment and restoration of historic properties and facilities at the end of their useful lives; and

•Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and unconventional plays.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. In addition, to the extent these expenditures are assumed by a buyer as a result of a disposition, it may result in our incurring substantial costs if the buyer is unable to satisfy these obligations. Any actual or perceived failure by us to comply with existing or future laws, regulations and other requirements could result in administrative or civil penalties, criminal fines, other enforcement actions or third-party litigation against us. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our business, financial condition, results of operations and cash flows in future periods, as well as our ability to implement and advance our Climate-related Risk Strategy could be adversely affected.

Existing and future laws, regulations and internal initiatives relating to global climate change, such as limitations on GHG emissions or provisions aimed at reducing such emissions, may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products.

Continuing political and societal attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions, such as cap and trade regimes, specific emission standards, carbon taxes, restrictive permitting, increased fuel efficiency standards and incentives or mandates for renewable and alternative energy. Although we may support the intent of legislative and regulatory measures aimed at addressing climate-related risks, the specifics of how and when they are enacted could result in a material adverse effect to our business, financial condition, results of operations and cash flows in future periods as well as our ability to implement and advance our Climate-related Risk Strategy.

For example, in 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the "polluter pays" model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme


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weather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, other states have introduced similar measures, and it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities. Additionally, legislation has been introduced in certain U.S. states that would provide Attorneys General, insurers and individuals a right to recover against certain energy companies for alleged climate change impacts. Should such legislation become law, we may be exposed to additional, significant liabilities.

Furthermore, in December 2023, the EPA published a final rule that revises the regulations governing, among other things, the emission of methane and volatile organic compounds from new oil and gas production facilities and emission guidelines for states to use when revising Clean Air Act implementation plans to limit methane emissions from existing oil and gas facilities. However, in 2025 the EPA moved to dismantle some climate-related regulations (e.g. delaying compliance deadlines for methane standards and proposing to eliminate most obligations under the Greenhouse Gas Reporting Program). These policy swings create additional uncertainty for companies who need to plan for operations that will endure through administrations. These regulatory changes may also complicate our ability to access non-operated or joint venture emissions data to complete our inventory of emissions.

Additionally, international climate initiatives, such as the United Nations Conference of the Parties summits, continue to shape the global response to climate change. These summits can lead to commitments from numerous countries to meet the objectives of agreements like the Paris Agreement, through adopting country level regulation to reduce greenhouse gas emissions.

The implementation of current agreements and regulatory or judicial measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely increase our capital and operating expenses, impact the demand for our products, impose taxes on our products or operations, or require us to purchase emission credits or reduce emissions of GHGs from our operations. As a result, we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations.

For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company's response, see the "Contingencies—Climate Change” and "—Company Response to Climate-Related Risks" sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation.

Attention to global climate change has also resulted in pressure from and upon stockholders, financial institutions and other financial market participants to potentially limit or discontinue investments, insurance and funding to oil and gas companies. For example, a significant number of financial institutions have pledged to meet the goal of net zero by 2050, as well as setting interim targets for 2030 or earlier. While these targets do not prohibit financial sector stakeholders from doing business with oil and gas companies, stakeholders may self-impose limits. Conversely, we also face pressure from some in the investment community and certain public interest groups to limit the focus on ESG in our decision-making, arguing that ESG considerations do not relate to financial outcomes. As public pressure continues to mount on the financial sector, our costs of capital may increase.

Furthermore, attention to global climate change has resulted in an increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Beginning in 2017 and continuing through 2025, cities, counties, governments and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed by governmental entities. In 2025, a putative class action was filed against oil and gas companies, including ConocoPhillips, seeking to hold energy companies liable for increased home insurance premiums allegedly due to climate change losses. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. We believe these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change, and we will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we expect to incur substantial legal costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a failure or lack of diligence to meet our publicly stated ESG goals or alleging misrepresentation related to our ESG activity.


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Political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through sanctions, tax, tariffs and other legislation, executive orders and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; tariffs; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest groups. In addition, we may face regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane emissions standards, requirements restricting or prohibiting flaring and subsurface water disposal, more stringent environmental impact studies and reviews and policies inhibiting or curtailing LNG or crude oil exports. Similar regulatory shifts, including attendant higher costs and market access constraints, may also occur in international jurisdictions in which we currently operate or seek to operate.

Hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations, has historically attracted political and regulatory scrutiny. A range of local, state, federal and national laws and regulations currently govern, constrain or prohibit hydraulic fracturing in some jurisdictions. New or more stringent permitting, disclosure or other regulatory requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal, could result in increased costs, operating restrictions or operational delays or could limit the ability to develop oil and natural gas resources.

In addition, certain interest groups have also proposed ballot initiatives, contested lease sales and challenged project permits, for example, to restrict oil and natural gas development generally as well as specific projects, including the Willow project in Alaska. In the event that ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, liquidity and ability to implement and advance the Climate-related Risk Strategy.

Political and economic factors in international markets could have a material adverse effect on us.

Approximately 29 percent of our hydrocarbon production was derived from production outside the U.S. in 2025, and 31 percent of our proved reserves, as of December 31, 2025, were located outside the U.S. We are subject to risks associated with our operations in foreign jurisdictions and international markets, including changes in foreign governmental policies relating to crude oil, bitumen, LNG, natural gas or NGLs pricing and taxation; other regulatory or economic developments (including the macro effects of U.S. and international trade policies and disputes); disruptive geopolitical conditions such as recent conflict escalation in the Middle East and Eastern Europe; and international monetary and currency rate fluctuations. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy security and climate policies. In addition, some countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan government, have affected operations significantly in the past and may continue to do so in the future.

In addition, the U.S. government has the authority to prevent or restrict us from doing business in foreign jurisdictions or with certain parties. These restrictions and similar restrictions imposed by foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various jurisdictions. Diplomatic relations or policies between the U.S. government and one or more foreign jurisdictions may increase our expenses or impair our ability to collect awards in legal actions against such foreign jurisdictions. Changes in domestic and international policies and regulations may also restrict our ability to obtain or maintain licenses or permits necessary to operate in foreign jurisdictions, including those necessary for drilling and development of wells. Similarly, the declaration of a “climate emergency” could result in actions to limit exports of our products and other restrictions.

Any of these actions could adversely affect our business or operating results, including our ability to implement and advance the Climate-related Risk Strategy.


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Other Risk Factors Facing our Business or Operations

We may need additional capital in the future, and it may not be available on acceptable terms or at all.

We have historically relied primarily upon cash generated by our business to fund our operations and strategy; however, we have also relied from time to time on access to the capital markets for funding. There can be no assurance that additional financing will be available in the future on acceptable terms or at all. In addition, although we anticipate we will be able to repay our existing indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able to do so. Our ability to obtain additional financing or refinance our existing indebtedness when it matures or in accordance with our plans, will be subject to a number of factors, including market conditions, our operating performance, investor sentiment, risks impacting financial institutions and the credit markets more broadly and financial institution policies regarding the oil and gas industry. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, our business could be adversely affected.

In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. We and other industry companies have had our ratings reduced in the past due to negative commodity price outlooks. These major rating agencies are now considering ESG attributes when assessing credit profiles. While these assessments have limited impact today, they have the potential to pressure credit ratings over time. Any downgrade in our credit rating or announcement that our credit rating is under review for possible downgrade could increase the cost associated with any additional indebtedness we incur.

Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third parties with whom we do business.

The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing. Any default by any of our counterparties may result in our inability to perform our obligations under agreements we have made with third parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting counterparty, which could further adversely impact our results of operations.

Our ability to execute our capital return program is subject to certain considerations.

Ordinary dividends are authorized and determined by our Board of Directors 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 anticipated future capital needs;

•The level of distributions paid by comparable companies;

•Our operating expenses; and

•Other factors our Board of Directors deems relevant.

We paid a quarterly ordinary dividend to our shareholders in each quarter of 2025. Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time.

Additionally, as of December 31, 2025, up to $25.7 billion of share repurchase authority remained. 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 of Directors may consider when declaring dividends, among other factors. In the past, we have suspended our share repurchase program in response to market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so again in the future.

Any downward revision in the amount of our ordinary dividend or the volume of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.


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Risk Factors			Table of Contents

There are substantial risks with any acquisitions or divestitures we have completed or that we may choose to undertake.

We regularly review our portfolio and pursue growth through acquisitions and seek to divest noncore assets or businesses. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. Even if we do complete such transactions, our cash flow from operations may be adversely impacted or otherwise the transactions may not result in the benefits anticipated due to various risks, including, but not limited to (i) the failure of the acquired assets or businesses to meet or exceed expected returns, including risk of impairment; (ii) the inability to dispose of noncore assets and businesses on satisfactory terms and conditions; and (iii) the discovery of unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections are inadequate or we lack insurance or indemnities, including environmental liabilities, or with regard to divested assets or businesses, claims by purchasers to whom we have provided contractual indemnification. In addition, we may face difficulties in integrating the operations, technologies, products and personnel of any acquired assets or businesses.

Our technologies, systems and networks are subject to cybersecurity threats.

Our business is faced with growing cybersecurity threats as we increasingly rely on digital technologies across our business. Cybersecurity risks to our business, including our suppliers, third-party service providers, contractors, joint venture partners and external business partners, include but are not limited to:

•Unauthorized access to, or control of or disclosure of sensitive information about our business and our employees;

•Compromise of our data or systems, including corruption, sabotage, encryption or acts that otherwise render our data or systems unusable (or those of third parties with whom we do business, including third-party cloud and information technology (IT) service providers);

•Theft or manipulation of our proprietary information;

•Ransom;

•Extortion;

•Threats to the security of our facilities and infrastructure; and

•Cyber terrorism.

In addition, we have exposure to cybersecurity risks where our data and proprietary information are collected, hosted, and/or processed by third-party cloud and service providers. In addition, many of our vendors, including suppliers that are closely integrated into our business, have been victims of cybersecurity attacks that have accessed and exfiltrated information from their systems. Our risks may be exacerbated by a delay or failure to detect a cybersecurity incident or to understand the full extent of such incident notwithstanding our risk management processes and controls. We face risks associated with new and ever-increasing phishing techniques, hidden malware, as well as risks associated with electronic data proliferation and technology digitization. We also face increased risk with the increased sophistication of generative artificial intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time.

Our increasing reliance on IT in our production, distribution and marketing systems may allow cybersecurity threats to disrupt our oil and gas operations, both domestically and abroad.

If our data, IT, operational technology (OT), including industrial control and supervisory control and data acquisition (SCADA) systems were to be breached, damaged or disrupted due to a cybersecurity incident or cyber-attack (directly, indirectly through third parties or through the IT networks, servers, software, or infrastructure on which they rely), we could be subject to serious negative consequences. These consequences could include physical damage to production, distribution or storage assets; delay or prevention of delivery to markets; disruption or prevention of accurate accounting for production and settlement of transactions; negative impacts on public health, safety, the environment, economic security, or national security; financial impacts; business interruption; reputational damage; loss of employee, supplier, contractor, partner and/or public trust; reimbursement or other costs; increased compliance costs; regulatory investigations; litigation exposure and legal liability or regulatory fines; penalties or other external intervention.

Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and infrastructure that support our business. If we seek insurance against cybersecurity risks, it may be limited by the availability and increasing expense of sufficient coverage.

For additional information regarding our cybersecurity risk management, strategy and governance, see Item 1C. Cybersecurity.


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Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Cybersecurity Risk Management and Strategy

Cybersecurity Risk Assessment and Management

We take a multilayered approach to cybersecurity risk management and strategy. Our IT/OT Security Program integrates administrative, technical, and physical controls against evolving cybersecurity threats, and includes enterprise IT and OT security architecture, cybersecurity operations, data privacy and governance, supply chain security, and governance, risk, and compliance. Additionally, it is designed to identify, assess, and manage cybersecurity risks and protect the confidentiality, integrity, and availability of our data, IT, and OT.

Cybersecurity is a component of our IT/OT Security Program, which we periodically review and adapt to respond to new and evolving circumstances, cybersecurity threats and regulations. We evaluate security, privacy, and resiliency risks, including those related to cybersecurity, in our overall Enterprise Risk Management (ERM) program's annual risk assessment process. This annual risk assessment process takes into account broader risks based on likelihood, potential consequences, and mitigations, such as operational and economic impact; health, safety and environmental impact; and reputational and financial implications. This risk assessment is discussed with members of the ELT, Audit and Finance Committee (AFC) of the Board of Directors, and Board of Directors on at least an annual basis.

We consult recognized security frameworks, such as the National Institute of Standards and Technology Cybersecurity Framework to organize, improve, and assess our IT/OT Security Program to manage and reduce cybersecurity risk. We deploy, configure, and maintain various technologies designed to enforce security policies, detect and protect against cybersecurity threats, and help safeguard IT and OT assets. We operate a Cybersecurity Operation Center (CSOC) to ingest threat intelligence, monitor cybersecurity threats, coordinate incident response resources and manage response times.

Our Global Computer Security Incident Response Plan (CSIRP) establishes the framework for our response to cybersecurity incidents. Under the CSIRP, cybersecurity incidents are escalated based on a defined incident categorization to the Chief Information Security Officer (CISO) and senior leaders, including the Chief Digital & Information Officer (CD&IO), General Counsel, Chief Financial Officer, and other cybersecurity program stakeholders, such as the AFC and/or the full Board of Directors. We also conduct incident response exercises at least annually, which are facilitated by internal team members and, in some instances, with assistance from third-party experts.

Physical controls are designed to work in conjunction with digital and cybersecurity controls to help protect the company’s IT and OT assets from physical threats. Our Chief Security Officer is responsible for a physical security program including site plans, cameras, security systems monitoring, and access control and badging systems to manage physical security risks.

Our governing policies, standards and procedures create a structured approach to managing cybersecurity risk. Information security requirements for employees, contractors and partners are detailed in the ConocoPhillips Information Security & Protection Policy. Our workforce is required to complete information security training annually, and we periodically communicate ways to recognize and avoid cybersecurity threats to our workforce.

Engagement of Third Parties

We engage third-party cybersecurity consultants and experts to supplement staffing of our CSOC, as well as to help us assess, validate, and enhance our security practices, including conducting cybersecurity maturity assessments, vulnerability assessments and penetration tests.

As part of the cybersecurity incident response process described above, we engage third-party experts as needed to support incident response, such as external legal advisors, cybersecurity forensic firms and other specialists.


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			Table of Contents

Third-Party Service Provider Risk Management

Our third-party risk management process is designed to identify, assess, and mitigate risks associated with third-party service providers, including cybersecurity risks. An initial assessment is conducted to assess the cybersecurity risks associated with a third-party provider based on various criteria, such as whether the third-party provider has access to our network, data, and information systems. Third-party providers that are identified through the initial assessment as warranting further review are subject to additional risk assessment. In parallel, we have designed a contracting process to mitigate cybersecurity risks by specifying the rights and responsibilities of the parties.

Risks from Material Cybersecurity Threats

While we are subject to ongoing cybersecurity threats, we do not believe that the risks from previous threats have materially affected or are reasonably likely to materially affect the company, including our business strategy, results of operations or financial condition. Nevertheless, we recognize cybersecurity threats are on-going and evolving, and our program is designed to identify and manage those threats. See Item 1A. Risk Factors—Our technologies, systems and networks are subject to cybersecurity threats for more information on our risks relating to our technologies, systems, and networks.

Cybersecurity Governance

Management's Role

A dedicated CISO leads the IT/OT Security Team and is responsible for our cybersecurity risk management and strategy. The CISO has over 20 years of experience in security, of which 18 years is specific to cybersecurity and has served as a CISO since 2013, having joined ConocoPhillips as CISO in 2022. The CISO holds a master’s degree and is a Certified Information Security Professional. The CISO reports to the CD&IO, who holds a master’s degree in information technology and has served as Chief Information Officer/Chief Technology Officer and various roles in information technology for over 29 years. The CD&IO reports to the Executive Vice President, Global Operations and Technical Functions. This management team assesses and manages risks associated with cybersecurity.

Board of Directors' Oversight

While our cybersecurity management team is responsible for the day-to-day assessment and management of material risks from cybersecurity threats, the ConocoPhillips Board of Directors has oversight responsibility for our ERM program and the individual risk management programs comprising our ERM program, including cybersecurity risk management. To help maintain effective Board of Directors' oversight across the entire enterprise, the Board of Directors delegates certain elements of its oversight function to individual committees. The AFC assists the Board of Directors in fulfilling its oversight of our ERM program and cybersecurity.

The Board of Directors receives a report on cybersecurity annually, and the AFC receives reports on cybersecurity multiple times a year. For meetings where cybersecurity is not on the formal agenda, the AFC will receive a pre-read that includes cybersecurity updates or discussion topics. During these reviews, management discusses various topics, including information relating to IT/OT Security strategy, program management, cybersecurity risks and threats, and provides briefings on notable cybersecurity attacks, including those relating to third-party service providers, if known. In addition to this regular reporting, significant cybersecurity risks or threats may also be escalated on an as needed basis to the AFC and Board of Directors.

Item 3. Legal Proceedings

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would not be a material effect to our consolidated financial position.

ConocoPhillips has elected to use a $1 million threshold for disclosing certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party. ConocoPhillips believes proceedings under this threshold are not material to ConocoPhillips' business and financial condition. Applying this threshold, there are no such proceedings to disclose for the year ended December 31, 2025. See Note 9 for information regarding other legal and administrative proceedings.


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			Table of Contents

Item 4. Mine Safety Disclosures

Not applicable.

Information about our Executive Officers


Name	Age*	Current and Prior Positions (up to five years)

Kontessa S. Haynes-Welsh	51	Vice President, Finance and Controller (since March 2025) Vice President and Treasurer (November 2022 to February 2025) Chief Accounting Officer (March 2021 to October 2022) Assistant Controller (January 2020 to February 2021) Manager, Strategy, Planning and Portfolio Management (June 2018 to January 2020)
Heather G. Hrap	53	Senior Vice President, Human Resources and Real Estate and Facilities Services (since March 2022) Vice President, Human Resources (January 2019 to February 2022)
Kirk L. Johnson	50	Executive Vice President, Global Operations and Technical Functions (since June 2025) Senior Vice President, Global Operations (March 2024 to May 2025) Senior Vice President, Lower 48 Assets and Operations (May 2022 to February 2024) Vice President, Corporate Planning and Development (June 2021 to April 2022) President Canada (June 2018 to May 2021)
Ryan M. Lance	63	Chairman of the Board of Directors and Chief Executive Officer (since May 2012)
Andrew D. Lundquist	65	Senior Vice President, Government Affairs (since February 2013)
Andrew M. O'Brien	51	Chief Financial Officer and Executive Vice President, Strategy & Commercial (since June 2025) Senior Vice President, Strategy, Commercial, Sustainability and Technology (March 2024 to May 2025) Senior Vice President, Global Operations (November 2022 to February 2024) Vice President and Treasurer (May 2021 to October 2022) Vice President, Corporate Planning and Development (August 2020 to May 2021)
Nicholas G. Olds	56	Executive Vice President, Lower 48 and Global HSE (since January 2026) Executive Vice President, Lower 48 (November 2022 to December 2025) Executive Vice President, Global Operations (September 2021 to October 2022) Senior Vice President, Global Operations (August 2020 to September 2021) Vice President, Corporate Planning and Development (June 2018 to August 2020)
Kelly B. Rose	59	Senior Vice President, Legal, General Counsel and Corporate Secretary (since September 2018)

*On February 17, 2026.

There are no family relationships among any of the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from the date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 12, 2026.


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			Table of Contents

Part II

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

ConocoPhillips’ common stock is traded on the NYSE under the symbol “COP.”

Cash Dividends Per Share


	2025		2024
	Ordinary			Ordinary	VROC
First	$	0.78		0.58	0.20
Second	0.78			0.58	0.20
Third	0.78			0.58	0.20
Fourth	0.84			0.78	—
Number of Stockholders of Record at January 31, 2026*					46,054

Dividends shown above reflect the quarter in which the dividends were declared.

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency listing.

In the fourth quarter of 2024, we incorporated the prior VROC equivalent payment into our ordinary dividend. The declaration of ordinary dividends and VROC are subject to the discretion and approval of our Board of Directors. The Board has adopted a dividend declaration policy providing that the declaration of any dividends will be determined quarterly. For more information on factors considered when determining the level of these distributions, see “Item 1A —Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

Issuer Purchases of Equity Securities


					Millions of Dollars
Period	Total Number of Shares Purchased*	Average Price Paid Per Share		Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

October 1-31, 2025	5,084,464	$	90.02	5,084,464	$	26,274
November 1-30, 2025	3,277,056	88.28		3,277,056	25,985
December 1-31, 2025	2,963,034	92.81		2,963,034	25,710
	11,324,554			11,324,554

*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.

In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our previous authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate repurchases. As of December 31, 2025, we had repurchased $39.3 billion of shares since 2016. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Except as limited by applicable legal requirements, repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares. For more information, see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”


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Stock Performance Graph

The following graph shows the cumulative TSR for ConocoPhillips’ common stock in each of the five years from December 31, 2020 to December 31, 2025. The graph also compares the cumulative total returns for the same five-year period with the S&P 500 Index and our performance peer group consisting of APA Corporation, Chevron, Devon Energy, Diamondback Energy, EOG Resources, ExxonMobil and Occidental Petroleum weighted according to the respective peer’s stock market capitalization at the beginning of each annual period. Due to Chevron’s acquisition of Hess Corporation in 2025, Hess Corporation has been removed from our performance peer group and has been excluded from all five years of the peer group performance.

The comparison assumes $100 was invested on December 31, 2020, in ConocoPhillips stock, the S&P 500 Index and ConocoPhillips’ peer group and assumes that all dividends were reinvested. The cumulative total returns of the peer group companies' common stock do not include the cumulative total return of ConocoPhillips’ common stock. The stock price performance included in this graph is not necessarily indicative of future stock price performance.


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Management’s Discussion and Analysis			Table of Contents

Item 7. Management’s Discussion and Analysis of Financial Condition and

Results of Operations

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 62.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss).

Business Environment and Executive Overview

ConocoPhillips is one of the world’s leading E&P companies, based on both production and reserves, with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2025, we employed approximately 9,900 people worldwide and had total assets of $122 billion.

Overview

At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.

Throughout 2025, the price of crude oil has been volatile due to multiple macroeconomic and geopolitical forces which slowed global oil demand growth concurrent with higher oil production from OPEC Plus and other major oil producing countries. We continue to closely monitor the macroeconomic environment, including any impacts from tariffs, and the ongoing market volatility in the energy landscape and across global markets for implications to our business, results of operations and financial condition.

As the global energy industry continues to evolve, we remain committed to creating long-term value for our stockholders. We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets. Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles, which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.

Total company production in 2025 was 2,375 MBOED, yielding cash provided by operating activities of $19.8 billion. We invested $12.6 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of $9.0 billion through our ordinary dividend and share repurchases. In 2025, we returned $4.0 billion through the ordinary dividend, inclusive of an increase in December of eight percent to 84 cents per share. In addition, we returned $5.0 billion to shareholders through share repurchases. As of December 31, 2025, we have repurchased $39.3 billion of shares of our authorized share repurchase program since 2016. In February 2026, we declared a first-quarter ordinary dividend of 84 cents per share.


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Management’s Discussion and Analysis			Table of Contents

In November 2024, we completed our acquisition of Marathon Oil. In the first half of 2025, we completed the asset integration of Marathon Oil and by year-end 2025 achieved more than $1 billion of synergies on a run-rate basis and approximately $1 billion of one-time benefits. These one-time benefits include $0.5 billion recognized previously upon close of the transaction related to the utilization of foreign tax credits, with the remainder related to cash tax benefits from net operating losses, most of which was recognized in 2025. See Note 3.

Separately, in the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026. In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing is expected to contribute approximately $0.8 billion in cost reductions. We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.

In August 2025, we announced a total disposition target of $5 billion by year-end 2026. We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026. Completed dispositions to date include the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion, the Anadarko Basin for net proceeds of $1.2 billion and other noncore Lower 48 and Corporate assets for approximately $1.3 billion. See Note 3.

As part of our LNG strategy to build a dynamic portfolio and expand our footprint across the value chain, we have various commercial LNG offtake agreements in North America totaling 10.2 MTPA with offtake commencing between 2026-2031. Furthermore, we currently have a total regasification capacity in Europe of approximately 6.7 MTPA. We continue to progress discussions across all major LNG producing and consuming regions and markets to further add high-quality positions to our portfolio.

Operationally, we remain focused on safely executing the business while also progressing key strategic initiatives. At Willow, we made significant progress and achieved critical milestones, successfully completing our largest winter season. In the Lower 48, we integrated Marathon Oil assets into our portfolio, focusing on operating and capital efficiencies. Internationally, we became the sole operator of the Kebabangan Cluster (KBBC) PSC in Malaysia in January 2025, extending the PSC to 2050 and making KBBC our first operated producing asset in Malaysia. In Canada, we achieved first oil at Surmont Pad 104W-A in December 2025. Additionally, our equity LNG projects continued to advance at NFE and NFS in Qatar and PALNG on the U.S. Gulf Coast.

The relevant provisions of the One Big Beautiful Bill Act (OBBBA), enacted on July 4, 2025, were implemented during the third quarter of 2025. While OBBBA did not have a material effect on our effective tax rate for the quarter, the changes introduced by the legislation impacted our current and deferred tax calculations, with approximately $0.4 billion cash tax benefit recognized in 2025.

Production for 2025 was 2,375 MBOED, representing an increase of 388 MBOED or 20 percent compared to 2024. After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.


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Management’s Discussion and Analysis			Table of Contents

Business Environment

The energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. Our profitability, reserves base, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our foundational principles guide our differential value proposition to deliver competitive returns on and of capital to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.

Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2025. In 2025, the company retired $0.7 billion principal amount of debt at maturity. We ended the year with cash and cash equivalents and restricted cash of $6.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion, maintaining balance sheet strength.

Peer-leading distributions. We believe in delivering value to our shareholders via our return of capital framework, which consists of a growing, sustainable ordinary dividend and share repurchases. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2025, we returned $4.0 billion to shareholders through our ordinary dividend and $5.0 billion through share repurchases. Our combined dividends and share repurchases of $9.0 billion represented 46 percent of our net cash provided by operating activities.

Disciplined investments. Our goal is to optimize free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.

•Exercise capital discipline. Our global portfolio is deep, diverse and durable. As we consider our capital investment opportunities, we apply a rigorous framework that we believe allows for competitive free cash flow to be available to return to shareholders. We believe allocating capital based on low cost of supply resource base will result in higher returns and drive resiliency through low prices. We also balance our investments between short- and longer-cycle projects. For example, in 2025, we continued to invest in short-cycle projects in the Lower 48 segment, as well as longer-cycle projects such as Willow in Alaska. This capital allocation framework seeks to maximize free cash flow through price cycles. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A.

•Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis, and report to management. Managing costs is critical to maintaining a competitive position in our cyclical industry and positively impacts our ability to deliver strong cash from operations.

In the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026. In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing, is expected to contribute approximately $0.8 billion in cost reductions. We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.

•Optimize our portfolio. We continually evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2025, we divested assets in Lower 48 including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, assets in the Anadarko basin and other noncore assets. See Note 3.


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Management’s Discussion and Analysis			Table of Contents

•Add to our proved reserve base. We primarily add to our proved reserve base in three ways:

•Acquire interests in existing or new fields.

•Apply new technologies and processes to improve recovery from existing fields.

•Successfully explore, develop and exploit new and existing fields.

Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. Our reserve replacement was 80 percent in 2025, reflecting a net decrease from dispositions in noncore assets in Lower 48 and lower prices, partially offset by development drilling activity and extensions and discoveries. Our organic reserve replacement, which excludes a net decrease of 165 MMBOE from sales and purchases, was 99 percent in 2025.

In the three years ended December 31, 2025, our reserve replacement was 145 percent. Our organic reserve replacement during the three years ended December 31, 2025, which excludes a net increase of 905 MMBOE related to sales and purchases, was 106 percent.

See "Supplementary Data - Oil and Gas Operations" for more information.

Environmental, Social and Governance performance. We are committed to the efficient and effective exploration and production of oil and natural gas. We seek to deliver energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process, and remain committed to our targets. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors to executive leadership and business unit managers.

For more information on our commitment to responsible and reliable ESG performance, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.


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Management’s Discussion and Analysis			Table of Contents

Commodity Prices

Commodity prices and the associated realizations are the most significant factor impacting our profitability and related returns on and of capital to our shareholders. Dynamics that could influence world energy markets and commodity prices include, but are not limited to, global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tariffs, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial, operational and ESG priorities that underpin our value proposition.

Our earnings and operating cash flows generally correlate with price levels for crude oil and natural gas, which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2023.

The following table presents average prices for 2025 compared to 2024:



Industry Prices	2025		2024	Change
Brent ($ per BBL)	$	69.06	80.76	(14)	%
WTI ($ per BBL)	64.81		75.72	(14)	%
Henry Hub ($ per MMBTU)	3.43		2.27	51	%

Average Realized Prices
Bitumen realized price ($ per BBL)	$	40.74	47.92	(15)	%

Total realized price ($ per BBL)	$	47.01	58.39	(19)	%

Crude and bitumen prices were lower through 2025 as global oil supplies increased faster than global oil demand.

Natural gas prices increased due to stronger demand and lower inventory levels relative to 2024.

Our worldwide annual average realized price decrease was driven by lower crude and bitumen prices.


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Management’s Discussion and Analysis			Table of Contents

Key Operating and Financial Summary

Significant items during 2025 and recent announcements included the following:

•Reported fourth-quarter 2025 earnings per share of $1.17;

•Generated cash provided by operating activities of $19.8 billion;

•Distributed $9.0 billion to shareholders, including $5.0 billion through share repurchases and $4.0 billion through the ordinary dividend;

•Ended the year with cash, cash equivalents, restricted cash and short-term investments of $7.4 billion and long-term investments of $1.1 billion.

•Delivered full-year total company and Lower 48 production of 2,375 MBOED and 1,484 MBOED, respectively;

•Completed the integration of Marathon Oil and doubled synergy capture to more than $1 billion on a run-rate basis in 2025; achieved an additional ~$1 billion of one-time benefits;

•On track to achieve incremental cost reductions and margin enhancements of more than $1 billion on a run-rate basis by year-end 2026;

•Closed $3.2 billion in dispositions in 2025 and on track to meet $5 billion total disposition target by year-end 2026;

•Continued to advance Willow project in Alaska and equity LNG projects at NFE and NFS in Qatar and PALNG on the U.S. Gulf Coast; all projects remain on schedule with NFE startup expected in the second half of 2026;

•Achieved Lower 48 drilling and completion efficiency improvements of more than 15% year over year;

•Advanced commercial LNG strategy by placing initial 5 MTPA of PALNG Phase 1 offtake; secured additional offtake of 5 MTPA to bring total commercial offtake portfolio to 10 MTPA;

•Signed an agreement to extend the Waha Concession in Libya through 2050, with new fiscal terms, subject to normal regulatory approvals; and

•Achieved first oil at Surmont Pad 104W-A in the fourth quarter, ahead of schedule.

Outlook

Capital, Production and DD&A

Guidance for 2026 includes capital expenditures of approximately $12 billion.

Production guidance is 2.33 to 2.36 MMBOED. First-quarter 2026 production is expected to be 2.30 to 2.34 MMBOED, inclusive of weather-related downtime.

DD&A is expected to be $11.7 to $11.9 billion.

Operating Segments

We manage our operations through five operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; and Asia Pacific. Effective in the fourth quarter of 2025, we determined that our former Other International operating segment, which consisted of activities associated with prior operations in other countries, was no longer an operating segment. Residual results are aggregated into Corporate and Other. Our historical operating segment reporting has been recast to reflect this change.

Our combined Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense; impacts from certain debt transactions; corporate overhead and certain technology activities, including licensing revenues; and unrealized holding gains or losses on equity securities. All cash and cash equivalents and short-term investments are included in Corporate and Other.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.


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Results of Operations			Table of Contents

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons between 2025 and 2024. For discussion of year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2024 10-K.

Consolidated Results

Summary Operating Statistics


	2025	2024	2023
Average Net Production
Crude oil (MBD)
Consolidated operations	1,133	969	923
Equity affiliates	12	13	13
Total crude oil	1,145	982	936

Natural gas liquids (MBD)
Consolidated operations	411	304	279
Equity affiliates	8	8	8
Total natural gas liquids	419	312	287

Bitumen (MBD)	133	122	81

Natural gas (MMCFD)
Consolidated operations	2,859	2,200	1,916
Equity affiliates	1,206	1,233	1,219
Total natural gas	4,065	3,433	3,135

Total Production (MBOED)	2,375	1,987	1,826
Total Production (MMBOE)	867	727	666


	Dollars Per Unit
Average Sales Prices
Crude oil (per BBL)
Consolidated operations	$	65.58	76.74	78.97
Equity affiliates	68.94		76.76	78.45
Total crude oil	65.62		76.74	78.96

Natural gas liquids (per BBL)
Consolidated operations	20.59		22.43	22.12
Equity affiliates	46.20		51.53	47.09
Total natural gas liquids	21.07		23.19	22.82

Bitumen (per BBL)	40.74		47.92	42.15

Natural gas (per MCF)
Consolidated operations	3.40		2.61	3.89
Equity affiliates	6.83		8.22	8.46
Total natural gas	4.44		4.69	5.69


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Results of Operations			Table of Contents


	Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical, lease rental, and other	$	226	309	236
Leasehold impairment	91		6	53
Dry holes	90		40	109
Total Exploration Expenses	$	407	355	398

Total Company Production

We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2025, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar, Libya and Equatorial Guinea.

Total production of 2,375 MBOED increased 388 MBOED or 20 percent in 2025 compared with 2024. Production increases include:

•New wells online in the Lower 48, Canada, Australia, Norway, Alaska, Libya, China and Malaysia.

•Our acquisition of Marathon Oil in the fourth quarter of 2024.

The increase in production during 2025 was partly offset by normal field decline.

After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.


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Results of Operations			Table of Contents

Income Statement Analysis

Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

Below is select financial data provided on a consolidated basis. The full income statement can be found in Item 8. Financial Statements and Supplementary Data.


	Millions of Dollars
Years Ended December 31	2025		2024	2023

Sales and other operating revenues	$	58,944	54,745	56,141
Equity in earnings of affiliates	1,335		1,705	1,720
Gain (loss) on dispositions	731		51	228

Purchased commodities	22,325		20,012	21,975
Production and operating expenses	10,331		8,751	7,693
Selling, general and administrative expenses	893		1,158	705

Depreciation, depletion and amortization	11,500		9,599	8,270





Other expenses	20		181	2
Income tax provision (benefit)	4,668		4,427	5,331

Sales and other operating revenues increased $4,199 million in 2025, primarily due to higher volumes of $6,197 million, inclusive of sales volumes from our acquisition of Marathon Oil and higher realized gas prices of $824 million and the timing of sales as compared to 2024. These increases were partially offset by lower realized crude and bitumen prices of $4,615 million and $349 million, respectively. See Note 3.

Equity in earnings of affiliates decreased $370 million in 2025, primarily due to lower earnings driven by lower LNG and crude prices.

Gain (loss) on dispositions increased $680 million in 2025, primarily due to gains associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC and other noncore assets in our Lower 48 segment. See Note 3.

Purchased commodities increased $2,313 million in 2025, primarily due to higher purchased volumes associated with our acquisition of Marathon Oil, higher natural gas prices and higher purchased crude volumes, partly offset by lower crude prices. See Note 3

Production and operating expenses increased $1,580 million in 2025, primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and $216 million of severance costs related to a restructuring. See Note 3 and See Note 14.

Selling, general and administrative expenses decreased $265 million in 2025, primarily due to the absence of transaction expenses of $545 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025. See Note 3 and See Note 14.

DD&A increased $1,901 million in 2025 primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and higher production volumes. See Note 3.

Other expenses decreased $161 million primarily related to the absence of a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 7.

See Note 15—Income Taxes for information regarding our income tax provision and effective tax rate.


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Results of Operations			Table of Contents

Segment Results

Unless otherwise indicated, discussion of Segment Results is after-tax.

A summary of the company’s net income (loss) by business segment follows:


	Millions of Dollars
Years Ended December 31	2025		2024	2023

Alaska	$	730	1,326	1,778
Lower 48	5,264		5,175	6,461
Canada	741		712	402
Europe, Middle East and North Africa	1,224		1,189	1,189
Asia Pacific	1,167		1,724	1,961

Segments Total	9,126		10,126	11,791
Corporate and Other	(1,138)		(881)	(834)
Net income (loss)	$	7,988	9,245	10,957

For further discussion of segment results, see the following pages.


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Results of Operations			Table of Contents

Alaska



	2025		2024	2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	5,638	6,553	7,098
Production and operating expenses ($MM)	2,158		1,951	1,829
Depreciation, depletion and amortization ($MM)	1,399		1,299	1,061
Taxes other than income taxes ($MM)	438		470	497

Net income (loss) ($MM)	$	730	1,326	1,778

Average Net Production
Crude oil (MBD)	177		173	173
Natural gas liquids (MBD)	15		15	16
Natural gas (MMCFD)	41		39	38
Total Production (MBOED)	199		194	195
Total Production (MMBOE)	73		71	71

Average Sales Prices
Crude oil ($ per BBL)	$	71.79	81.73	83.05
Natural gas ($ per MCF)	3.81		3.90	4.47

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2025, Alaska contributed 12 percent of our consolidated liquids production and one percent of our consolidated natural gas production.

Net Income (Loss)

Alaska reported earnings of $730 million in 2025, compared with earnings of $1,326 million in 2024.

Decreases to earnings included lower revenues resulting from lower commodity prices of $509 million, partly offset by higher produced volumes of $78 million. Additional decreases to earnings included higher production and operating expenses of $151 million, driven by higher lease operating expenses and well work activity and severance costs related to a restructuring, and higher DD&A of $73 million, primarily driven by higher rates. See Note 14.

Production

Average production increased five MBOED in 2025 compared with 2024, primarily due to new wells online and less downtime.

The production increase was partly offset by normal field decline.


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Lower 48



	2025		2024	2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	41,395	37,026	38,237
Production and operating expenses ($MM)	5,856		4,751	4,199
Depreciation, depletion and amortization ($MM)	8,121		6,442	5,722
Taxes other than income taxes ($MM)	1,506		1,378	1,352

Net income (loss) ($MM)	$	5,264	5,175	6,461

Average Net Production
Crude oil (MBD)	749		602	569
Natural gas liquids (MBD)	382		279	256
Natural gas (MMCFD)	2,119		1,625	1,457
Total Production (MBOED)	1,484		1,152	1,067
Total Production (MMBOE)	542		422	389

Average Sales Prices
Crude oil ($ per BBL)	$	63.18	74.17	76.19
Natural gas liquids ($ per BBL)	20.64		22.02	21.73
Natural gas ($ per MCF)	1.74		0.87	2.12

The Lower 48 segment consists of operations located in the contiguous U.S. and related commercial operations. During 2025, the Lower 48 contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

Net Income (Loss)

Lower 48 reported earnings of $5,264 million in 2025, compared with earnings of $5,175 million in 2024.

Increases to earnings included higher revenues resulting from higher volumes of $3,890 million, inclusive of volumes from our acquisition of Marathon Oil, partly offset by lower commodity prices of $1,999 million, driven by lower crude prices. Additional increases included higher gains on dispositions of $494 million, primarily associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, and other noncore assets.

Decreases to earnings included higher DD&A of $1,330 million and higher production and operating expenses of $875 million, primarily driven by impacts from our acquisition of Marathon Oil. See Note 3.

Production

Total average production increased 332 MBOED in 2025 compared with 2024, primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Bakken and Midland Basin and the impact from our acquisition of Marathon Oil. See Note 3.

Production increases were partly offset by normal field decline.

Dispositions

In 2025, we completed multiple divestitures, including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $699 million, the Anadarko Basin for net proceeds of $1.2 billion and other noncore assets for $1.1 billion. Production from these assets averaged approximately 33 MBOED in 2024. See Note 3.


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Results of Operations			Table of Contents

Canada



	2025		2024	2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	3,625	3,514	3,006
Production and operating expenses ($MM)	833		902	619
Depreciation, depletion and amortization ($MM)	556		639	420
Taxes other than income taxes ($MM)	27		31	26

Net Income (Loss) ($MM)	$	741	712	402

Average Net Production
Crude oil (MBD)	17		17	9
Natural gas liquids (MBD)	6		6	3
Bitumen (MBD)	133		122	81
Natural gas (MMCFD)	125		115	65
Total Production (MBOED)	177		164	104
Total Production (MMBOE)	65		60	38

Average Sales Prices
Crude oil ($ per BBL)	$	55.35	64.47	66.19
Natural gas liquids ($ per BBL)	22.54		29.59	26.13
Bitumen ($ per BBL)	40.74		47.92	42.15
Natural gas ($ per MCF)*	1.02		0.54	1.80

*Average sales prices include unutilized transportation costs.

The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. In 2025, Canada contributed nine percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Canada reported earnings of $741 million in 2025 compared with earnings of $712 million in 2024.

Increases to earnings included higher revenues resulting from higher volumes of $142 million and the timing of sales as compared with 2024 partly offset by lower commodity prices of $303 million. Increases to earnings included lower DD&A of $63 million driven by year-end 2024 upward reserve revisions and higher other income of $62 million primarily from a change in fair value measurement associated with the Surmont contingent consideration arrangement. Additional increases to earnings included lower production and operating expenses of $52 million driven by the absence of prior-year planned turnaround activity at Surmont. See Note 11.

Production

Total average production increased 13 MBOED in 2025 compared with 2024. Increases to production resulted from new wells online in the Montney and Surmont and the absence of prior-year planned turnaround activity at Surmont.

Production increases were partly offset by normal field decline.


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Europe, Middle East and North Africa



	2025		2024	2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	6,484	5,788	5,854
Production and operating expenses ($MM)	962		671	593
Depreciation, depletion and amortization ($MM)	912		761	587
Taxes other than income taxes ($MM)	46		41	39

Net income (loss) ($MM)	$	1,224	1,189	1,189

Consolidated Operations
Average Net Production
Crude oil (MBD)	131		118	112
Natural gas liquids (MBD)	8		4	4
Natural gas (MMCFD)	511		371	308
Total Production (MBOED)	224		184	168
Total Production (MMBOE)	82		67	61

Average Sales Prices
Crude oil ($ per BBL)	$	68.95	80.92	83.96
Natural gas liquids ($ per BBL)	16.53		40.29	41.13
Natural gas ($ per MCF)	10.87		10.70	12.68

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 2025, our Europe, Middle East and North Africa operations contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.

Net Income (Loss)

The Europe, Middle East and North Africa segment reported earnings of $1,224 million in 2025 compared with earnings of $1,189 million in 2024.

Earnings in 2025 included higher revenues resulting from higher volumes of $296 million, including volumes from our Equatorial Guinea assets from the acquisition of Marathon Oil, partly offset by lower overall realized commodity prices of $185 million, driven by lower crude prices. See Note 3.

Decreases to earnings included higher production and operating expenses of $88 million, primarily from our acquisition of Marathon Oil. See Note 3.

Consolidated Production

Average consolidated production increased 40 MBOED in 2025, compared with 2024. The consolidated production increase was primarily due to the impact from assets acquired from Marathon Oil as well as new wells online in Norway and Libya. See Note 3.

The production increase was partly offset by normal field decline.


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Results of Operations			Table of Contents

Asia Pacific



	2025		2024	2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	1,770	1,847	1,913
Production and operating expenses ($MM)	367		384	391
Depreciation, depletion and amortization ($MM)	460		425	455
Taxes other than income taxes ($MM)	57		109	117

Net income (loss) ($MM)	$	1,167	1,724	1,961

Consolidated Operations
Average Net Production
Crude oil (MBD)	59		59	60

Natural gas (MMCFD)	63		50	48
Total Production (MBOED)	70		67	68
Total Production (MMBOE)	26		25	25

Average Sales Prices
Crude oil ($ per BBL)	$	71.05	82.42	84.79

Natural gas ($ per MCF)	3.59		3.74	3.95

The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 2025, Asia Pacific contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Asia Pacific reported earnings of $1,167 million in 2025, compared with $1,724 million in 2024.

Decreases to earnings included lower revenues resulting from lower commodity prices of $206 million. Additional decreases to earnings included lower earnings from equity affiliates of $271 million, primarily due to lower LNG sales prices and higher exploration expenses of $64 million, primarily driven by dry hole expenses associated with certain wells in Malaysia and Australia.

Consolidated Production

Average consolidated production increased three MBOED in 2025, compared with 2024. Increases to production were primarily due to development activity in Bohai Bay in China and Gumusut in Malaysia.

Production increases were partly offset by normal field decline.


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Corporate and Other


	Millions of Dollars
	2025		2024	2023
Net income (loss)
Net interest expense	$	(494)	(379)	(360)
Corporate G&A expenses	(486)		(716)	(357)
Technology	(144)		(137)	(34)
Other income (expense)	(14)		352	(70)
	$	(1,138)	(880)	(821)

Net interest expense consists of interest and debt expense, net of interest income and capitalized interest. Net interest expense increased in 2025 due to higher interest expense driven by debt assumed from our acquisition of Marathon Oil. See Note 3 and Note 7.

Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $230 million in 2025 compared with 2024, primarily due to the absence of transaction expenses of $432 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025. See Note 3 and Note 14.

Technology includes our investments in low-carbon technology opportunities as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG.

Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in “Other” decreased by $366 million in 2025 compared with 2024. This was primarily due to the absence of a tax benefit of $455 million as a result of the acquisition of Marathon Oil in 2024 and the subsequent utilization of foreign tax credits. The earnings decrease was partly offset by an increase due to the absence of a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 3, Note 7 and Note 15.


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Capital Resources and Liquidity			Table of Contents

Capital Resources and Liquidity

Financial Indicators


	Millions of Dollars Except as Indicated
	2025			2024	2023

Net cash provided by operating activities	$	19,796		20,124	19,965
Cash and cash equivalents	6,497			5,607	5,635
Short-term investments	484			507	971

Short-term debt	1,020			1,035	1,074
Total debt	23,444			24,324	18,937
Total equity	64,487			64,796	49,279
Percent of total debt to capital*	27		%	27	28
Percent of floating-rate debt to total debt	1		%	1	2

Balance Sheet related line items are shown as of December 31st.

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 2025, the primary uses of our available cash were $12.6 billion to support our ongoing capital expenditures and investments program; $5.0 billion to repurchase common stock; $4.0 billion to pay the ordinary dividend; and $0.9 billion to retire debt, partly offset by proceeds from asset sales of $3.2 billion. In 2025, cash and cash equivalents increased by $0.9 billion to $6.5 billion. See Note 3 and Note 7.

At December 31, 2025, we had cash and cash equivalents of $6.5 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.5 billion of liquidity. In addition, we have long-term investments in debt securities of $1.1 billion. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, capital return program and required debt payments.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities in 2025 totaled $19.8 billion, compared with $20.1 billion for 2024, and $20.0 billion for 2023. The decrease in 2025 compared to 2024 resulted from lower commodity prices, mostly offset by operations from the 2024 Marathon Oil acquisition. See Note 3.

The increase in cash provided by operating activities in 2024 compared to 2023 is due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024. The increase in production was partly offset by lower commodity prices and lower distributions from equity affiliates. See Note 3.

Our short- and long-term operating cash flows are highly dependent on the prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile, driven by market conditions beyond our control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.


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The level of absolute production volumes, as well as the product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 2,375 MBOED in 2025, an increase of 388 MBOED or 20 percent compared to 2024. First-quarter 2026 production is expected to be 2.30 MMBOED to 2.34 MMBOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices.

Investing Activities

In 2025, we invested $12.6 billion in capital expenditures and investments, $0.5 billion of which was primarily payments towards our equity investments in LNG projects, including NFE4, NFS3 and PALNG, while the remainder funded our operating capital program. Capital expenditures invested in 2024 and 2023 were $12.1 billion and $11.2 billion, respectively. See the “Capital Expenditures and Investments” section.

Proceeds from asset sales were $3.2 billion in 2025 compared with $0.3 billion in 2024 and $0.6 billion in 2023. In 2025, we sold Lower 48 assets in the Anadarko basin for net proceeds of $1.2 billion and our interest in the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion. Additionally, we sold other noncore Lower 48 and Corporate assets for approximately $1.3 billion. See Note 3.

In the fourth quarter of 2024, after exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A. Inc. and Union Oil Company of California for $296 million, before customary adjustments. See Note 3.

In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $2.7 billion of cash after customary adjustments. We funded this transaction by issuing new long-term debt. See Note 3 and Note 7.

We invest in short-term and long-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Funds needed for short-term investments to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities of less than one year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan are invested in highly liquid instruments with maturities of greater than one year. See Note 10 and Note 17.

Investing activities in 2025 included net purchases of $55 million of investments. We had net sales of $502 million of short-term investments and net purchases of $557 million of long-term investments. See Note 17.


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Financing Activities

Our debt balance at December 31, 2025 was $23.4 billion compared with $24.3 billion at December 31, 2024. The current portion of debt, including payments for finance leases, is $1.0 billion.

In 2025, the company retired $0.7 billion principal amount of debt at maturity, consisting of $0.2 billion of our 3.35% Notes, $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures.

In November 2024, we acquired Marathon Oil. At closing, the acquisition was valued at $16.5 billion and was allocated to assets acquired and liabilities assumed. ConocoPhillips common stock was issued and exchanged for outstanding Marathon Oil shares. With the acquisition, we also assumed Marathon Oil's debt of approximately $4.6 billion. See Note 3 and Note 7.

In 2024, the company retired $726 million principal amount of Notes at maturity consisting of $265 million of our 3.35% Notes and $461 million of our 2.125% Notes. In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion; a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt (with priority for Marathon Oil debt assumed); a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt; and remarketing of $0.4 billion in available municipal bonds. The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 7.

In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities. See Note 7.

In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.

Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

The revolving credit facility supports ConocoPhillips Company’s ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2025.

In November 2025, Fitch affirmed our long-term credit rating. The current credit ratings on our long-term debt are:

•Fitch: “A” with a “stable” outlook

•S&P: “A-” with a “stable” outlook

•Moody's: “A2" with a “stable" outlook

See Note 7 for additional information on debt and the revolving credit facility.

We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, upon downgrade of our credit ratings. If our credit ratings are downgraded from their current levels, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.


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Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At December 31, 2025 and 2024, we had direct bank letters of credit of $331 million and $278 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Shelf Registration

We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section. For information about our debt balances and related debt financing transactions, see the "Significant Changes in Capital - Financing Activities" section.

We believe in delivering value to our shareholders through our return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and through-cycle share repurchases. We anticipate returning greater than 30 percent of cash from operating activities through cycles. Our 2025 total capital returned was $9.0 billion.

Consistent with our commitment to deliver value to shareholders, for the full year of 2025, we paid ordinary dividends of $3.18 per common share. In 2024 we paid ordinary dividends of $2.52 and VROC payments of $0.60 per common share and in 2023 we paid ordinary dividends of $2.11 and VROC payments of $2.50 per common share. In February 2026, we declared a first-quarter ordinary dividend of $0.84 per common share payable March 2, 2026, to shareholders of record on February 18, 2026.

Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time.

In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our prior authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate repurchases. Share repurchases were $5.0 billion, $5.5 billion, and $5.4 billion in 2025, 2024, and 2023, respectively. As of December 31, 2025, share repurchases since the inception of our current program totaled 486.1 million shares for $39.3 billion since 2016. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors.

For more information on factors considered when determining the levels of returns of capital see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

As of December 31, 2025, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $45.0 billion. We expect to fulfill $5.0 billion of these obligations in 2026 with the remainder over the next 25 years. A substantial amount of LNG offtake and other product purchases are expected to be offset in the same or approximately same periods by cash received from the related sales transactions. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator.

The following table summarizes our aggregate future contractual purchase obligations as of December 31, 2025:


	Millions of Dollars
	2025
LNG offtake, regasification and related vessels	$	29,722
Other capacity obligations	10,890
Other product purchases	3,094
Other obligations	1,271
Total	$	44,977


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Capital Expenditures and Investments


	Millions of Dollars
	2025		2024		2023
Alaska	$	3,607	3,194		1,705
Lower 48	6,702		6,510		6,487
Canada	593		551		456
Europe, Middle East and North Africa	1,194		1,021		1,111
Asia Pacific	342		370		354
Segments Total	12,438		11,646		10,113
Corporate and Other	115		472		1,135
Capital Program*	$	12,553	$	12,118	$	11,248

* Excludes capital related to acquisitions of businesses, net of cash acquired.

Our capital expenditures and investments for the three-year period ended December 31, 2025, totaled $35.9 billion. The 2025 capital expenditures and investments supported key operating activities and acquisitions, primarily:

•Appraisal and development activities in Alaska related to the Western North Slope, inclusive of Willow, and development activities in the Greater Kuparuk Area.

•Development activities in the Lower 48, primarily in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.

•Appraisal and development activities in the Montney as well as development and optimization of Surmont in Canada.

•Development and appraisal activities across assets in Norway and development activities in Libya.

•Continued development activities in China.

•Investments in NFE4, NFS3 and PALNG.

2026 Capital Budget

In February 2026, we announced our 2026 operating plan capital is expected to be approximately $12 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.


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Guarantor Summarized Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.

The following tables present summarized financial information for the Obligor Group, as defined below:

•The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.

•Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information.

•Non-Obligated Subsidiaries are excluded from this presentation.

Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented separately below:

Summarized Income Statement Data


	Millions of Dollars
	2025
Revenues and Other Income	$	38,564
Income (loss) before income taxes*	7,316

Net income (loss)	7,988

*Includes approximately $11.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data


	Millions of Dollars
	December 31, 2025
Current assets	$	8,206
Amounts due from Non-Obligated Subsidiaries, current	855
Noncurrent assets	130,320
Amounts due from Non-Obligated Subsidiaries, noncurrent	11,231
Current liabilities	4,947
Amounts due to Non-Obligated Subsidiaries, current	1,244
Noncurrent liabilities	74,824
Amounts due to Non-Obligated Subsidiaries, noncurrent	52,813

Contingencies

We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See “Critical Accounting Estimates” and Note 9 for information on contingencies.

Legal and Tax Matters

We are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations and climate change. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process


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facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 15.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:

•U.S. Federal Clean Air Act, which governs air emissions;

•U.S. Federal Clean Water Act, which governs discharges to water bodies;

•EU Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals;

•U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;

•U.S. Federal Oil Pollution Act of 1990, under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;

•U.S. Federal Emergency Planning and Community Right-to-Know Act, which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;

•U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;

•U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; and

•EU Trading Directive resulting in EU Emissions Trading Scheme (EU ETS).

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada.

An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards that are designed to meet government requirements. Our practices continually evolve as technology improves and regulations change.


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We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their equivalents in their respective jurisdictions. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of December 31, 2025, there were 20 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $834 million in 2025 and are expected to be approximately $1.0 billion in each of 2026 and 2027. Capitalized environmental costs were $669 million in 2025 and are expected to be about $750 million and $550 million in 2026 and 2027, respectively.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2025, our balance sheet included total accrued environmental costs of $220 million, compared with $206 million at December 31, 2024, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

See Item 1A. Risk Factors—We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations and Note 9 for information on environmental litigation.


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Climate Change

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on GHG emissions reduction. These laws apply or could apply in countries where we have interests or may have interests in the future. Additionally, some laws have been rescinded or delayed, creating policy swings that result in compliance uncertainty. Laws in this field continue to evolve and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our operational results and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include:

Emissions trading schemes.

•EU ETS is the program through which many of the EU member states aim to reduce emissions. Our cost of compliance with the EU ETS in 2025 was approximately $21 million (net share before-tax).

•The U.K. Emissions Trading Scheme (U.K. ETS) is the program with which the U.K. has replaced the EU ETS. Our cost of compliance with the U.K. ETS in 2025 was approximately $2.2 million (net share before-tax).

GHG regulations for emissions reductions.

•The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. There was no cost of compliance related to this regulation in 2025, as our Surmont asset outperformed its target benchmark intensity over the full year reporting period.

•As of April 2024, the British Columbia Output Based Pricing System (BC OBPS) regulation requires facilities or linear operations (such as oil and gas gathering systems) with emissions equal to or greater than 10,000 metric tonnes of carbon dioxide or equivalent per year to remit payments on the difference between actual emissions and allowable emissions based on product and activity benchmarks. The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments for 2025 are not due until later in 2026. Based on interim benchmarks, our BC OBPS obligation is expected to total a maximum of $12.3 million (net share before-tax) for Montney in 2025.

•In 2024, the EU passed regulation on the reduction of methane emissions in the energy sector that will apply a methane limit on oil and gas imports to the EU, as well as mandate the monitoring, reporting, verification and reduction of methane emissions.

•Our APLNG assets in Australia are subject to the Safeguard Mechanism, enacted through the National Greenhouse and Energy Reporting Act 2007. In the previous Australian financial year of July 1, 2024, to June 30, 2025, our operated downstream APLNG facility was in excess of its baseline emissions, while the upstream partner-operated facilities were below their baseline emissions. As there was a surplus of eligible carbon units across the joint venture, there was no expense incurred by ConocoPhillips for the 2025 Australian financial year.

•In 2024 the U.S. EPA published final rulemaking for New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc). Implementing this regulation across our U.S. portfolio will result in additional compliance costs.

Carbon taxes in certain jurisdictions.

•Effective April 1, 2025, the Canadian federal government set the consumer carbon price to zero and no longer requires a consumer carbon tax going forward. This is separate from the obligated industrial carbon pricing schemes of Alberta TIER and BC OBPS, which remain in place. Our operations outside of industrial carbon pricing schemes were minimal at Surmont for the first quarter of 2025, and no Federal Fuel charges were incurred at Montney in 2025.

•Our cost of compliance with Norwegian carbon legislation in 2025 was approximately $42 million (net share before-tax).

Other environmental regulations.

•The White House Council on Environmental Quality (CEQ) issued final National Environmental Policy Act implementation regulations (NEPA Phase 2) in 2024. Since then, the DC Circuit Court has suggested that CEQ lacks authority to adopt any binding regulations, introducing potential uncertainty into the regulatory process.

•Climate Superfund laws. In 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the “polluter pays” model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme weather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities.


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•Climate Private Action laws. In 2025, California, New Hampshire, and Oregon introduced bills seeking to create a private right of action for individuals to bring strict liability claims for alleged damages related to climate change impacts (including non-economic, actual and punitive damages). These bills also authorize insurance companies to pursue subrogation claims to recover damages for amounts paid to insureds for climate change impacts.

Non-regulatory initiatives or agreements.

•The Global Methane Pledge (GMP) was launched at COP26 by the EU and the U.S., a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.

•The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change set out a process for achieving global emissions reductions. Accordingly, parties to the Paris Agreement have set targets to reduce emissions by 2030. While the current administration has officially withdrawn the U.S. from the Paris Agreement, some U.S. states have indicated that they plan to remain committed to the goals of the agreement.

Regulated sustainability disclosures.

Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement. In June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state; in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures; and in the EU, the Corporate Sustainability Reporting Directive is expected to be finalized in 2026.

Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:

•Whether and to what extent legislation or regulation is enacted;

•The timing of the introduction of such legislation or regulation;

•The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation;

•The price placed on GHG emissions (either by the market or through a tax);

•The GHG emissions reductions required;

•The price and availability of offsets;

•The amount and allocation of allowances;

•Technological and scientific developments leading to new products or services;

•Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature); and

•Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

See Item 1A. Risk Factors—Existing and future laws, regulations and internal initiatives relating to global climate changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products and Note 9 for information on climate change litigation.

Company Response to Climate-Related Risks

The objective of our Climate-related Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, emissions reduction technologies, alternative energy technologies and changes in consumer trends. The strategy guides our choices around portfolio composition, emissions reductions, targets, incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.

Our Climate-related Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our operational emissions-reduction targets. First, meeting global energy demand requires a focus on delivering production that will best compete in any energy demand scenario. This production will be delivered from resources with a competitive cost of supply and low operational GHG intensity, as well as portfolio diversity by market and asset type. Next, our focus is on delivering superior returns through the cycles based on our foundational principles of balance sheet strength, peer-leading distributions and disciplined investments. Finally,


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to drive accountability for the emissions that are within our ownership, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.

Key elements of the Climate-related Risk Strategy include:

•Strategic flexibility and portfolio composition

◦Building a resilient asset portfolio with a focus on low cost of supply and low operational GHG intensity to meet global energy demand.

◦Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.

◦Testing our portfolio against future energy demand scenarios through a comprehensive scenario planning process that helps us assess the resilience of our corporate strategy to climate risk.

•Scope 1 and 2 GHG emissions targets and reductions

◦Setting targets for emissions over which we have ownership and control.

◦Reducing emissions through the marginal abatement cost curve process.

•LNG and technology

◦Building an attractive LNG portfolio as an important component of responsibly meeting global energy demand due to LNG's opportunity to displace higher-emissions fuels such as coal for electricity generation.

◦Evaluating potential investments in emerging alternative energy sources and low-carbon technologies.

•External engagement

◦Supporting a well-designed, economy-wide price on carbon and development of other policy and legislation to address end-use emissions.

◦Working with our suppliers and commercial partners to understand our emissions along the value chain.

Our Climate-related Risk Strategy does not include a Scope 3 emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions. This is why we have consistently supported a well-designed, economy wide price on carbon as well as the development of other policies or legislation that could address end-use emissions. We have also supported policy interests beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct federal regulation of methane.

In support of addressing our Scope 1 and 2 emissions, we have made recent progress in several key areas.

•Completed our 2025 scope 1 and 2 emissions reduction projects within the allotted capital and cost budget. These projects will support our GHG emissions intensity reduction target of 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.

•Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative for the second consecutive year.

•Achieved our target of zero routine flaring by the end of 2025 for heritage ConocoPhillips assets by taking all economically viable steps to eliminate routine flaring in accordance with the World Bank Zero Routine Flaring Initiative.

•Introduced a new commitment to maintain flaring intensity of less than 0.75 percent of gas produced at operated assets, to be implemented in 2026.

See Item 1A. Risk Factors—Our ability to successfully execute on our plans to reduce our operational GHG emissions intensity is subject to a number of risks and uncertainties, and such reductions may be costly and challenging to achieve.

New Accounting Standards

For discussion of new accounting standards, see Note 23.


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Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1 for descriptions of our significant accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or 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.

Oil and Gas Accounting

Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been recognized.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.

At year-end 2025, we held $10.0 billion of net capitalized unproved property costs. These capitalized costs consist primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $8.7 billion is concentrated in the Lower 48 Basins, primarily the Delaware, Eagle Ford and Bakken Basins, where we have an ongoing significant and active development program. Outside of the Lower 48 Basins, the remaining $1.3 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.

At year-end 2025, total suspended well costs were $243 million, compared with $196 million at year-end 2024. For additional information on suspended wells, including an aging analysis, see Note 5.


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Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our geosciences and reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates. See “Supplementary Data - Oil and Gas Operations” for additional information.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to PSCs, reported under the “economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. We would expect reserves from these contracts to decrease when product prices rise and increase when prices decline.

The estimation of proved reserves is also important to the income statement because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2025, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $80 billion and the DD&A recorded on these assets in 2025 was approximately $11.2 billion. The estimated proved developed reserves for our consolidated operations were 4.5 billion BOE at the end of 2024 and 4.2 billion BOE at the end of 2025. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2025 would have increased by an estimated $1,250 million.

Business Combination—Valuation of Oil and Gas Properties

For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 – “Business Combinations” and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates.

Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgment and are based on industry, market and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate is recorded. Subsequent to the acquisition date, and not later than one year from the acquisition date, we record any material adjustments to the initial estimate based on new information obtained that would have existed as of the date of the acquisition. Any adjustment that arises from information obtained that did not exist as of the date of acquisition is recorded in the period the adjustment arises. See Note 3.


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Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the periods in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period.

Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. Since quoted market prices are usually not available, the fair value is typically based on the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. Estimating future asset removal costs requires significant judgment. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change between the time of initial recognition of the liability and future settlement of our obligation.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. See Note 6.


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Projected Benefit Obligations

The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by $500 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount rate assumption would increase annual benefit expense by $50 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual benefit expense by $50 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a significant reduction in the expected years of future service of present employees or the elimination of the accrual of defined benefits for some or all of their future services for a significant number of employees, we could recognize a curtailment gain or loss. See Note 14.

Contingencies

A number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages and underpayments associated with environmental remediation, tax, contracts and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure; however, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and Note 9.

Income Taxes

We are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weigh the evidence based on objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing oil and gas prices). See Note 15.

We regularly assess and, if required, establish accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit from an uncertain tax position when it is more likely than not the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note 15.


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Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning development or replacement of reserves and future dividends. You can often identify our forward-looking statements by the words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.

We based our forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect or inaccurate, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:

•Effects of volatile commodity prices, including prolonged periods of low commodity prices, which may adversely impact our operating results and our ability to execute on our strategy and could result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.

•Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict; geopolitical tensions; security threats on facilities and infrastructure; global health crises; the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries; or the resulting company or third-party actions in response to such changes.

•The potential for insufficient liquidity or other factors, such as those described herein, that could impact our ability to repurchase shares and declare and pay dividends, whether fixed or variable.

•Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

•Reductions in our reserve replacement rates, whether as a result of significant declines in commodity prices or otherwise.

•Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

•Failure to progress or complete announced and future development plans related to constructing, modifying or operating E&P and LNG facilities, or unexpected changes in costs, inflationary pressures or technical equipment related to such plans.

•Significant operational or investment changes imposed by legislative and regulatory initiatives and international agreements addressing environmental concerns, including initiatives addressing the impact of global climate change, such as limiting or reducing GHG emissions; regulations concerning hydraulic fracturing, methane emissions, flaring or water disposal; and prohibitions on commodity exports.

•Broader societal attention to and efforts to address climate change may cause substantial investment in and increased adoption of competing or alternative energy sources.

•Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate-related Risk Strategy.

•Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.

•Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.

•Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events; war; terrorism; cybersecurity threats or information technology failures, constraints or disruptions.


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•Liability for remedial actions, including removal and reclamation obligations, under existing or future environmental regulations and litigation.

•Liability resulting from pending or future litigation or our failure to comply with applicable laws and regulations.

•General domestic and international economic, political and diplomatic developments, including deterioration of international trade relationships; the imposition of trade restrictions or tariffs relating to commodities and material or products (such as aluminum and steel) used in the operation of our business; expropriation of assets; changes in governmental policies relating to commodity pricing, including the imposition of price caps; sanctions; or other adverse regulations or taxation policies.

•Competition and consolidation in the oil and gas E&P industry, including competition for sources of supply, services, personnel and equipment.

•Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment.

•Challenges or delays to our execution of, or successful implementation of any future asset dispositions or acquisitions we elect to pursue; potential disruption of our operations, including the diversion of management time and attention; our inability to realize anticipated cost savings or capital expenditure reductions; difficulties integrating acquired businesses and technologies; or other unanticipated changes.

•Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we anticipate, if at all.

•The operation, financing and management of risks of our joint ventures.

•The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.

•Uncertainty as to the long-term value of our common stock.

•The factors generally described in Part I—Item 1A in this 2025 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.


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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors risks. The Chief Financial Officer and Executive Vice President, Strategy and Commercial, who reports to the Chief Executive Officer, monitors commodity price risk and risks resulting from foreign currency exchange rates and interest rates.

Commodity Price Risk

Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the following objectives:

•Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas consumers, to floating market prices.

•Enable us to use market knowledge to capture opportunities such as moving physical commodities to more profitable locations and storing commodities to capture seasonal or time premiums. We may use derivatives to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity contracts we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at December 31, 2025. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes or held for purposes other than trading at December 31, 2025 and 2024, was immaterial to our consolidated cash flows and net income.


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Interest Rate Risk

The following table provides information about our debt instruments that are sensitive to changes in U.S. interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. A hypothetical 10 percent change in prevailing interest rates would not have a material impact on interest expense associated with our floating-rate debt. The fair value of the fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data. Changes to prevailing interest rates would not impact our cash flows associated with fixed-rate debt, unless we elect to repurchase or retire such debt prior to maturity.


	Millions of Dollars Except as Indicated
	Debt
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
Year-End 2025
2026	$	704	3.40	%	$	—	—	%
2027	777		4.82		—		—
2028	664		3.78		—		—
2029	995		6.78		—		—
2030	1,601		5.17		—		—
Remaining years	18,323		5.24		283		2.40	%
Total	$	23,064			$	283
Fair value	$	22,415			$	283

Year-End 2024
2025	$	735	3.87	%	$	—	—	%
2026	704		3.40		—		—
2027	778		4.82		—		—
2028	664		3.78		—		—
2029	997		6.78		—		—
Remaining years	19,924		5.23		283		2.97	%
Total	$	23,802			$	283
Fair value	$	22,714			$	283

Foreign Currency Exchange Risk

We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency exchange rate changes although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming year and acquisitions.

At December 31, 2025 and 2024, we had outstanding foreign currency exchange forward contracts hedging cross-border commercial activity and for purposes of mitigating our cash-related exposures. Although these forwards hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded directly in earnings. Since the gain or loss on the exchange contracts is offset by the gain or loss from remeasuring cash related balances, and since our aggregate position in the forwards was not material, there would be no material impact to our income from an adverse hypothetical 10 percent change in the December 2025 or December 2024 exchange rates.

The gross notional and fair value of these positions at December 31, 2025 and 2024, were immaterial.


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Item 8. Financial Statements and Supplementary Data

ConocoPhillips


Index to Financial Statements
			Page
Reports of Management			67

Reports of Independent Registered Public Accounting Firm (PCAOB ID #42)			68

Financial Statements
Consolidated Income Statement for the years ended December 31, 2025, 2024 and 2023			71

Consolidated Statement of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023			72

Consolidated Balance Sheet at December 31, 2025 and 2024			73

Consolidated Statement of Cash Flows for the years ended December 31, 2025, 2024 and 2023			74

Consolidated Statement of Changes in Equity for the years ended December 31, 2025, 2024 and 2023			75

Notes to Consolidated Financial Statements
Note 1—Accounting Policies			76
Note 2—Inventories			80
Note 3—Acquisitions and Dispositions			80
Note 4—Investments, Loans and Long-Term Receivables			84

Note 5—Suspended Wells and Exploration Expenses			86
Note 6—Asset Retirement Obligations and Accrued Environmental Costs			88
Note 7—Debt			89
Note 8—Guarantees			93
Note 9—Contingencies and Commitments			94
Note 10—Derivatives and Financial Instruments			96
Note 11—Fair Value Measurement			100
Note 12—Equity			102
Note 13—Non-Mineral Leases			103
Note 14—Employee Benefit Plans			106
Note 15—Income Taxes			118
Note 16—Accumulated Other Comprehensive Income (Loss)			122
Note 17—Cash Flow Information			122
Note 18—Sales and Other Operating Revenues			123
Note 19—Related Party Transactions			123
Note 20—Other Financial Information			124
Note 21—Earnings Per Share			125
Note 22—Segment Disclosures and Related Information			125
Note 23—New Accounting Standards			129

Supplementary Information

Oil and Gas Operations			130


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Reports of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2025. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2025.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2025, and their report is included herein.


/s/ Ryan M. Lance			/s/ Andrew M. O'Brien

Ryan M. Lance			Andrew M. O'Brien
Chairman and Chief Executive Officer			Chief Financial Officer and Executive Vice President, Strategy & Commercial


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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of ConocoPhillips (the Company) as of December 31, 2025 and 2024, the related consolidated income statement, consolidated statements of comprehensive income, changes in equity and cash flows 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 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 17, 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 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 and Finance 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 the 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.


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			Table of Contents








			Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment associated with the Lower 48 segment

Description of the Matter			At December 31, 2025, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) associated with the Lower 48 segment was $47 billion, and depreciation, depletion and amortization (DD&A) expense associated with the Lower 48 segment was $8.1 billion for the year then ended. As described in Note 1, under the successful efforts method of accounting, DD&A of PP&E on producing hydrocarbon properties and related assets are determined by the unit-of-production method. The unit-of-production method uses proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers. Proved oil and gas reserves estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors. Significant judgment is required by the Company’s internal reservoir engineers in evaluating the data used to estimate proved oil and gas reserves. Estimating proved oil and gas reserves also requires the selection of inputs, including historical production, oil and gas price assumptions and future operating costs assumptions, among others. Auditing the Lower 48 segment’s DD&A calculation is complex because of the use of the work of the internal reservoir engineers and the evaluation of management’s determination of certain inputs described above used by the internal reservoir engineers in estimating proved oil and 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 internal controls over its processes to calculate the Lower 48 segment DD&A, including management’s controls over the completeness and accuracy of significant data provided to the internal reservoir engineers for use in estimating proved oil and gas reserves associated with the Lower 48 segment. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the proved oil and gas reserves estimates associated with the Lower 48 segment. In addition, in assessing whether we can use the work of the internal reservoir engineers, we evaluated the completeness and accuracy of the significant data and inputs described above used by the internal reservoir engineers in estimating proved oil and gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the accuracy of the DD&A calculation associated with the Lower 48 segment, including comparing the proved oil and gas reserves amounts used in the calculation to the Company’s reserve report.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 1949.

Houston, Texas

February 17, 2026


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			Table of Contents


Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on Internal Control Over Financial Reporting

We have audited ConocoPhillips’ 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, ConocoPhillips (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 income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and our report dated February 17, 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 under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management.” 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 17, 2026


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Financial Statements			Table of Contents


Consolidated Income Statement			ConocoPhillips


Years Ended December 31	Millions of Dollars
	2025		2024	2023
Revenues and other income
Sales and other operating revenues	$	58,944	54,745	56,141
Equity in earnings of affiliates	1,335		1,705	1,720
Gain (loss) on dispositions	731		51	228
Other income	538		452	485
Total revenues and other income	61,548		56,953	58,574

Costs and expenses
Purchased commodities	22,325		20,012	21,975
Production and operating expenses	10,331		8,751	7,693
Selling, general and administrative expenses	893		1,158	705
Exploration expenses	407		355	398
Depreciation, depletion and amortization	11,500		9,599	8,270
Impairments	26		80	14
Taxes other than income taxes	2,146		2,087	2,074
Accretion on discounted liabilities	378		325	283
Interest and debt expense	855		783	780
Foreign currency transaction (gain) loss	11		(50)	92
Other expenses	20		181	2
Total costs and expenses	48,892		43,281	42,286
Income (loss) before income taxes	12,656		13,672	16,288
Income tax provision (benefit)	4,668		4,427	5,331
Net income (loss)	$	7,988	9,245	10,957



Net income (loss) per share of common stock (dollars)
Basic	$	6.36	7.82	9.08
Diluted	6.35		7.81	9.06

Weighted-average common shares outstanding (in thousands)
Basic	1,252,042		1,178,920	1,202,757
Diluted	1,253,446		1,180,871	1,205,675

See Notes to Consolidated Financial Statements.


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Financial Statements			Table of Contents


Consolidated Statement of Comprehensive Income			ConocoPhillips


Years Ended December 31	Millions of Dollars
	2025		2024	2023
Net income (loss)	$	7,988	9,245	10,957
Other comprehensive income (loss), net of tax:









Defined benefit plans	55		3	55



Unrealized holding gain (loss) on securities	5		1	13


Foreign currency translation adjustments	502		(760)	197


Unrealized gain (loss) on hedging activities	—		(44)	62
Other comprehensive income (loss), net of tax	562		(800)	327
Comprehensive income (loss)	$	8,550	8,445	11,284

See Notes to Consolidated Financial Statements.


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Financial Statements			Table of Contents


Consolidated Balance Sheet			ConocoPhillips


At December 31	Millions of Dollars
	2025		2024
Assets
Cash and cash equivalents	$	6,497	5,607
Short-term investments	484		507
Accounts and notes receivable (net of allowance of $4 and $7, respectively)	5,813		6,695



Inventories	1,873		1,809
Prepaid expenses and other current assets	865		1,029
Total current assets	15,532		15,647
Investments and long-term receivables	10,185

CONOCOPHILLIPS 10-K