CONOCOPHILLIPS - Annual Report: 2024 (Form 10-K)

Foreign currency transaction (gain) loss(50)92 (100)Other expenses181 2 (47)Income tax provision (benefit)4,427 5,331 9,548

Sales and other operating revenues decreased $1,396 million in 2024, primarily due to lower realized natural gas and crude prices of $1,031 million and $791 million, respectively, and the timing of sales as compared to 2023. These decreases were partially offset by higher volumes of $2,659 million, inclusive of sales volumes from our acquisitions of Surmont and Marathon Oil, and higher realized bitumen prices of $258 million. See Note 3.

Gain (loss) on dispositions decreased $177 million in 2024, primarily due to the absence of gains associated with the divestitures of an equity investment and noncore assets in Lower 48 segment.

Purchased commodities decreased $1,963 million in 2024, primarily driven by lower natural gas and crude prices, partially offset by higher crude volumes.

Production and operating expenses increased $1,058 million in 2024, due to higher lease operating expenses and transportation costs in our Lower 48 and Alaska segments, higher volumes primarily in our Canada and Lower 48 segments, as well as higher expenses associated with the Surmont turnaround in our Canada segment. See Note 3.

Selling, general and administrative expenses increased $453 million in 2024, primarily due to transaction expenses of $545 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs. See Note 15.

DD&A increased $1,329 million in 2024 primarily due to higher volumes in our Lower 48 and Canada segments, higher rates in our Alaska and Lower 48 segments and the impact of our acquisition of Marathon Oil. See Note 3.

Foreign currency transaction (gain) loss for the year was improved by $142 million, primarily due to the absence of losses of $112 million associated with forward contracts in support of our Surmont acquisition. See Note 3.

Other expenses increased $179 million primarily related to a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 8.

See Note 16—Income Taxes for information regarding our income tax provision and effective tax rate.


41			ConocoPhillips 2024 10-K


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	2024		2023	2022

Alaska	$	1,326	1,778	2,352
Lower 48	5,175		6,461	11,015
Canada	712		402	714
Europe, Middle East and North Africa	1,189		1,189	2,244
Asia Pacific	1,724		1,961	2,736
Other International	(1)		(13)	(51)
Corporate and Other	(880)		(821)	(330)
Net income (loss)	$	9,245	10,957	18,680

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


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Results of Operations			Table of Contents

Alaska



	2024		2023	2022
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	6,553	7,098	7,905
Production and operating expenses ($MM)	1,951		1,829	1,703
Depreciation, depletion and amortization ($MM)	1,299		1,061	939
Taxes other than income taxes ($MM)	470		497	1,323

Net Income (Loss) ($MM)	$	1,326	1,778	2,352

Average Net Production
Crude oil (MBD)	173		173	177
Natural gas liquids (MBD)	15		16	17
Natural gas (MMCFD)	39		38	34
Total Production (MBOED)	194		195	200
Total Production (MMBOE)	71		71	73

Average Sales Prices
Crude oil ($ per bbl)	$	81.73	83.05	101.72
Natural gas ($ per mcf)	3.90		4.47	3.64

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2024, Alaska contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Alaska reported earnings of $1,326 million in 2024, compared with earnings of $1,778 million in 2023.

Decreases to earnings included lower revenues resulting from lower commodity prices of $73 million and the timing of sales as compared with 2023. Additional decreases to earnings included higher DD&A expenses of $175 million, driven by higher rates as a result of 2023 year-end downward reserve revisions as well as higher production and operating expenses of $90 million, driven by higher well work activity of $56 million and transportation related costs of $26 million.

Production

Average production decreased one MBOED in 2024 compared with 2023, primarily due to normal field decline.

The production decrease was partly offset by new wells online at our Western North Slope and Greater Kuparuk Area assets.

Acquisition of Additional Working Interest in Kuparuk River Unit and Prudhoe Bay Unit

After exercising our preferential rights, we completed an acquisition of additional working interest in both the Kuparuk River Unit and the Prudhoe Bay Unit in the fourth quarter of 2024. Production from the additional working interest averaged approximately five MBOED each month for November and December 2024. See Note 3.


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Results of Operations			Table of Contents

Lower 48



	2024		2023	2022
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	37,026	38,237	52,903
Production and operating expenses ($MM)	4,751		4,199	3,627
Depreciation, depletion and amortization ($MM)	6,442		5,722	4,865
Taxes other than income taxes ($MM)	1,378		1,352	1,693

Net Income (Loss) ($MM)	$	5,175	6,461	11,015

Average Net Production
Crude oil (MBD)	602		569	534
Natural gas liquids (MBD)	279		256	221
Natural gas (MMCFD)	1,625		1,457	1,402
Total Production (MBOED)	1,152		1,067	989
Total Production (MMBOE)	422		389	361

Average Sales Prices
Crude oil ($ per bbl)	$	74.17	76.19	94.46
Natural gas liquids ($ per bbl)	22.02		21.73	35.36
Natural gas ($ per mcf)	0.87		2.12	5.92

The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 2024, the Lower 48 contributed 63 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

Net Income (Loss)

Lower 48 reported earnings of $5,175 million in 2024, compared with earnings of $6,461 million in 2023.

Decreases to earnings included lower revenues resulting from lower overall commodity prices of $904 million and the timing of sales as compared with 2023, partly offset by higher volumes of $1,003 million, which includes volumes added from our acquisition of Marathon Oil. Additional decreases to earnings included higher DD&A of $562 million, driven by higher production of $250 million, higher rates of $181 million and impacts from our acquisition of Marathon Oil of $139 million; higher production and operating expenses of $431 million, driven by higher transportation related costs of $132 million, expenses associated with our acquisition of Marathon Oil of $110 million and higher lease operating expenses of $100 million; as well as the absence of gains associated with the divestiture of an equity investment of $100 million. See Note 3.

Production

Total average production increased 85 MBOED in 2024 compared with 2023, primarily due to new wells online from our development programs in Delaware Basin, Eagle Ford, Midland Basin and Bakken and the impact from assets acquired from Marathon Oil. See Note 3.

The production increase was partly offset by normal field decline and higher unplanned downtime across all basins.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil. The transaction added additional assets to our Lower 48 segment across several basins. Production from Lower 48 assets acquired from Marathon Oil averaged approximately 334 MBOED in the month of December 2024. See Note 3.

Planned Dispositions

We recently entered into agreements to sell noncore assets within our Lower 48 segment that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments. See Note 3.


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Results of Operations			Table of Contents

Canada



	2024		2023	2022
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	3,514	3,006	3,714
Production and operating expenses ($MM)	902		619	591
Depreciation, depletion and amortization ($MM)	639		420	402
Taxes other than income taxes ($MM)	31		26	21

Net Income (Loss) ($MM)	$	712	402	714

Average Net Production
Crude oil (MBD)	17		9	6
Natural gas liquids (MBD)	6		3	3
Bitumen (MBD)	122		81	66
Natural gas (MMCFD)	115		65	61
Total Production (MBOED)	164		104	85
Total Production (MMBOE)	60		38	31

Average Sales Prices
Crude oil ($ per bbl)	$	64.47	66.19	79.94
Natural gas liquids ($ per bbl)	29.59		26.13	37.70
Bitumen ($ per bbl)	47.92		42.15	55.56
Natural gas ($ per mcf)*	0.54		1.80	3.62

*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 2024, Canada contributed ten percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Canada reported earnings of $712 million in 2024 compared with earnings of $402 million in 2023.

Earnings included higher revenues resulting from higher volumes of $676 million; driven by our increased working interest in Surmont of $584 million and new wells online in the Montney of $180 million, partially offset by planned turnaround activity at Surmont impacting revenues by $157 million. Additionally, revenues increased from higher overall commodity prices of $153 million, driven primarily by higher bitumen prices. See Note 3.

Decreases to earnings included higher production and operating expenses of $215 million; driven by an impact of $175 million related to higher overall production, including our increased working interest in Surmont; as well as expenses of $55 million related to turnaround activity at Surmont. Additional decreases to earnings included higher DD&A expenses of $166 million resulting from higher volumes and the absence of a $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit in 2023.

Production

Total average production increased 60 MBOED in 2024 compared with 2023. Increases to production resulted from our increased working interest in Surmont as well as new wells online in the Montney and Surmont. See Note 3.

These production increases were partly offset by higher downtime resulting from a planned turnaround activity at a Surmont central processing facility and normal field decline.


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Results of Operations			Table of Contents

Europe, Middle East and North Africa



	2024		2023	2022
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	5,788	5,854	11,270
Production and operating expenses ($MM)	671		593	590
Depreciation, depletion and amortization ($MM)	761		587	736
Taxes other than income taxes ($MM)	41		39	39

Net Income (Loss) ($MM)	$	1,189	1,189	2,244

Consolidated Operations
Average Net Production
Crude oil (MBD)	118		112	107
Natural gas liquids (MBD)	4		4	3
Natural gas (MMCFD)	371		308	328
Total Production (MBOED)	184		168	165
Total Production (MMBOE)	67		61	60

Average Sales Prices
Crude oil ($ per bbl)	$	80.92	83.96	99.20
Natural gas liquids ($ per bbl)	40.29		41.13	54.52
Natural gas ($ per mcf)	10.70		12.68	33.39

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 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Net Income (Loss)

The Europe, Middle East and North Africa segment reported earnings of $1,189 million in 2024 compared with earnings of $1,189 million in 2023.

Earnings in 2024 included lower revenues resulting from lower overall commodity prices of $118 million and the timing of sales as compared with 2023, partly offset by higher volumes of $144 million, which includes $49 million from volumes added from our acquisition of Marathon Oil. Additional decreases to earnings included higher DD&A of $51 million.

Consolidated Production

Average consolidated production increased 16 MBOED in 2024, compared with 2023. The consolidated production increase was primarily due to new wells online and improved performance in Norway, as well as the impact from assets acquired from Marathon Oil. See Note 3.

The production increase was partly offset by normal field decline.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil. The transaction added Equatorial Guinea to our global portfolio which resides in our Europe, Middle East and North Africa segment. Production from Equatorial Guinea averaged approximately 40 MBOED in the month of December 2024. See Note 3.

Exploration Activity

In 2024, we charged approximately $40 million before-tax as dry hole expenses primarily for two partner operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea and the Busta suspended discovery well on license PL782S. See Note 6.


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Results of Operations			Table of Contents

Asia Pacific



	2024		2023	2022
Select financial data by segment before-tax ($MM)
Sales and other operating revenues ($MM)	$	1,847	1,913	2,606
Production and operating expenses ($MM)	384		391	365
Depreciation, depletion and amortization ($MM)	425		455	518
Taxes other than income taxes ($MM)	109		117	243

Net Income (Loss) ($MM)	$	1,724	1,961	2,736

Consolidated Operations
Average Net Production
Crude oil (MBD)	59		60	61
Natural gas (MMCFD)	50		48	114
Total Production (MBOED)	67		68	80
Total Production (MMBOE)	25		25	29

Average Sales Prices
Crude oil ($ per bbl)	$	82.42	84.79	105.52
	Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment

Description of the Matter	At December 31, 2024, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) was $77 billion, and depreciation, depletion and amortization (DD&A) expense was $9.4 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 steam-assisted gravity drainage facilities and certain pipeline and liquified natural gas assets (those which are expected to have a declining utilization pattern) 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, installed plant operating capacity and approved operating limits. 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 Company’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 the 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 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. 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. 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, including comparing the proved oil and gas reserves amounts used in the calculation to the Company’s reserve report.


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			Table of Contents


			Valuation and recognition of proved and unproved oil and gas properties acquired in a business combination

Description of the Matter			During 2024, the Company closed its acquisition of Marathon Oil Corporation resulting in the recognition of a provisional fair value of proved and unproved oil and gas properties within net properties, plants and equipment of $13.2 billion and $10.8 billion, respectively. As described in Note 3, the transaction was accounted for as a business combination using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. As also described in Note 3, the Company has not finalized its allocation of fair value to unproved properties. Oil and gas properties were valued by specialists using a discounted cash flow approach based on market participant assumptions. Significant inputs to the valuation of proved and unproved oil and gas properties include estimates of future commodity prices and production, future operating costs and discount rates using a market-based weighted average cost of capital. Auditing the Company's accounting for its provisional valuation of proved and unproved oil and gas properties within the Lower 48 segment is complex and judgmental due to the significant estimation required by management of reserves associated with the acquired assets and the sensitivity of significant assumptions used in determining the fair value. In evaluating the reasonableness of management’s estimates and assumptions used, the audit testing procedures performed required a high degree of auditor judgment and additional effort, including involving internal valuation specialists.

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 process to estimate the provisional fair value of the acquired proved and unproved oil and gas properties, including management’s review of the significant assumptions used as inputs to the fair value calculations and recording of the provisional valuation. To test the provisional fair value of the acquired proved and unproved oil and gas properties, our audit procedures included, among others, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data supporting the significant assumptions. For example, we compared certain significant assumptions to current industry and third-party data and historical results for reasonableness. We also performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the provisional fair value calculation. In addition, we involved internal valuation specialists to assist with certain significant assumptions included in the provisional fair value estimate. Furthermore, we evaluated the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the oil and gas reserves estimates and the valuation specialists used by the Company to prepare the provisional fair value of the acquired proved and unproved oil and gas properties. 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 used by the internal reservoir engineers in estimating oil and gas reserves by agreeing them to source documentation, as applicable, and we identified and evaluated corroborative and contrary evidence. As noted above, the Company has not finalized its allocation of fair value to unproved properties

/s/ Ernst & Young LLP

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

Houston, Texas

February 18, 2025


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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, 2024, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, ConocoPhillips (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.

As indicated under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management”, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Marathon Oil Corporation, which is included in the 2024 consolidated financial statements of the Company and constituted approximately 22% of consolidated total assets as of December 31, 2024, approximately 1% of revenues and other income and less than 1% of net income for the year ended December 31, 2024. Our audit of internal control over financial reporting of ConocoPhillips also did not include an evaluation of the internal control over financial reporting of Marathon Oil Corporation.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated 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, 2024, and the related notes and our report dated February 18, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included 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.


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			Table of Contents

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/

February 18, 2025


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Financial Statements			Table of Contents


Consolidated Income Statement			ConocoPhillips


Years Ended December 31	Millions of Dollars
	2024	2023	2022
Revenues and Other Income
Sales and other operating revenues	$
Equity in earnings of affiliates
Gain (loss) on dispositions
Other income
Total Revenues and Other Income

Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments			()
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gain) loss	()		()
Other expenses			()
Total Costs and Expenses
Income (loss) before income taxes
Income tax provision (benefit)
Net Income (Loss)	$

Net Income (Loss) Per Share of Common Stock (dollars)
Basic	$
Diluted

Average Common Shares Outstanding (in thousands)
Basic
Diluted

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
	2024	2023	2022
Net Income (Loss)	$
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period	()		()
Reclassification adjustment for amortization of prior service cost (credit) included in net income (loss)	()	()	()
Net change	()	()	()
Net actuarial gain (loss) arising during the period			()
Reclassification adjustment for amortization of net actuarial losses (gains) included in net income (loss)
Net change			()
Nonsponsored plans*		()
Income taxes on defined benefit plans	()	()
Defined benefit plans, net of tax			()
Unrealized holding gain (loss) on securities			()
Reclassification adjustment for (gain) loss included in net income	()	()	()
Income taxes on unrealized holding gain (loss) on securities		()
Unrealized holding gain (loss) on securities, net of tax			()
Foreign currency translation adjustments	()		()
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax	()		()
Unrealized gain (loss) on hedging activities	()
Income taxes on unrealized gain (loss) on hedging activities		()
Unrealized gain (loss) on hedging activities, net of tax	()
Other Comprehensive Income (Loss), Net of Tax	()		()
Comprehensive Income (Loss)	$

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
	2024	2023
Assets
Cash and cash equivalents	$
Short-term investments
Accounts and notes receivable (net of allowance of $ and $, respectively)
Accounts and notes receivable—related parties

Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables

Net properties, plants and equipment (net of accumulated DD&A of $ and $, respectively)
Other assets
Total Assets	$

Liabilities
Accounts payable	$
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities

Equity
Common stock ( shares authorized at $ par value) Issued (2024— shares; 2023— shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2024— shares; 2023— shares)	()	()
Accumulated other comprehensive income (loss)	()	()
Retained earnings
Total Equity
Total Liabilities and Equity	$

See Notes to Consolidated Financial Statements.


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Financial Statements			Table of Contents


Consolidated Statement of Cash Flows			ConocoPhillips

)))) )))) )))))

Years Ended December 31

Millions of Dollars

2024

2023

2022

Cash Flows From Operating Activities

Net income (loss)

Adjustments to reconcile net income (loss) to net cash provided by operating activities

Depreciation, depletion and amortization

Impairments

()

Dry hole costs and leasehold impairments

Accretion on discounted liabilities

Deferred taxes

Distributions more (less) than income from equity affiliates

(Gain) loss on dispositions

()

(Gain) loss on investment in Cenovus Energy

()

Millions of Dollars

See Notes to Consolidated Financial Statements.


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Notes to Consolidated Financial Statements			Table of Contents

Notes to Consolidated Financial Statements

operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. See Note 23.

•


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Notes to Consolidated Financial Statements			Table of Contents

•


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Notes to Consolidated Financial Statements			Table of Contents

•


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Notes to Consolidated Financial Statements			Table of Contents

•

• See Note 22.


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Notes to Consolidated Financial Statements			Table of Contents

Materials and supplies Total inventories$ Inventories valued on the LIFO basis$

The estimated excess of current replacement cost over LIFO cost of inventories was approximately $ million and $ million at December 31, 2024 and 2023, respectively.

billion, which primarily represented shares of ConocoPhillips common stock exchanged for each outstanding share of Marathon Oil common stock.

Cash transferred at close** Value attributable to Marathon Oil share-based awards Other liabilities incurred*** Total Fair Value (Millions)$

*Represents the fair value of approximately million shares of ConocoPhillips common stock issued to Marathon Oil stockholders. The fair value is based on the number of eligible shares of Marathon Oil common stock at a exchange ratio and ConocoPhillips' average stock price on November 22, 2024, which was $.

**Cash transferred at close primarily represents funds contributed to Marathon Oil for repayment of Marathon Oil's estimated commercial paper liabilities as of the closing date.

***Liabilities incurred are related to cash settled share-based awards and payment of cash in lieu of fractional Marathon Oil shares outstanding. These liabilities were settled prior to the end of 2024.

The transaction was accounted for as a business combination under FASB Topic ASC 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Fair value measurements were made for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as we identify new information about facts and circumstances that existed as of the acquisition date to consider. At December 31, 2024, remaining items to finalize include allocation of fair value to unproved properties. The impact of finalizing the fair value allocation is not expected to have a material impact to our consolidated financial statements.


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Notes to Consolidated Financial Statements			Table of Contents

billion, was allocated to the identifiable assets and liabilities based on their estimated fair values as of the acquisition date of November 22, 2024.

Accounts receivable, net Inventories Investments and long-term receivables Net properties, plants and equipment Other assets Total assets acquired$ Liabilities AssumedAccounts payable$ Accrued income and other taxes Employee benefit obligations Long-term debt Asset retirement obligations Deferred income taxes Other liabilities Total liabilities assumed$ Net assets acquired$

With the completion of the transaction, we acquired proved properties of approximately $ billion, with $ billion in Lower 48 and $ billion in Equatorial Guinea, and unproved properties of $ billion in Lower 48.

We recognized approximately $ million of transaction-related costs, the majority of which were expensed in the fourth quarter of 2024. These non-recurring costs related primarily to employee severance and related benefits, fees paid to advisors and the settlement of share-based awards for certain Marathon Oil employees based on the terms of the Merger Agreement. These transaction-related costs included $ million of employee severance expense. See Note 15.

For the year ended December 31, 2024, "Total Revenues and Other Income" and "Net Income (Loss)" associated with the acquired assets were $ million and income of $ million, respectively.

Alaska Acquisition

In the fourth quarter of 2024, after exercising our preferential rights, we completed an acquisition that increased our working interest by approximately percent in the Kuparuk River Unit and approximately percent in the Prudhoe Bay Unit from Chevron U.S.A. Inc. and Union Oil Company of California for $ million, before customary adjustments. The transaction was accounted for as an asset acquisition, with the consideration allocated primarily to PP&E.

Assets Held For Sale

In December 2024, we entered into an agreement to sell our interests in certain noncore assets in the Lower 48 segment for $ million, before customary adjustments. These assets have a net carrying value of approximately $ million, which consists primarily of $ million of PP&E and $ million of liabilities, primarily noncurrent AROs. These assets met held for sale criteria in the fourth quarter of 2024, and as of December 31, 2024, we reclassified the PP&E to “Prepaid expenses and other current assets” and the noncurrent liabilities to “Other accruals” on our consolidated balance sheet. This transaction is anticipated to close in the first quarter of 2025.


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million, before customary adjustments. This transaction is expected to close in the first half of 2025.

2023

Surmont Acquisition

In October 2023, we completed our acquisition of the remaining percent working interest in Surmont, an asset in our Canada segment, from TotalEnergies EP Canada Ltd. Following the acquisition, we own percent working interest in Surmont. billion (CAD $ billion) after customary adjustments:

Contingent consideration Total consideration$

The contingent consideration arrangement requires additional consideration to be paid to TotalEnergies EP Canada Ltd. up to $ billion CAD over a term. The contingent payments represent $ million for every dollar that WCS pricing exceeds $ per barrel during the month, subject to certain production targets being achieved. The undiscounted amounts we could pay under this arrangement was up to $ billion USD at closing. The fair value of the contingent consideration on the acquisition date was $ million and estimated by applying the income approach. For the year ended December 31, 2024, we have made payments of $ million USD under this arrangement, reflected in the "Other" line within the Financing Activities section of our Consolidated Statement of Cash Flows. See Note 12.

The transaction was accounted for as a business combination under FASB Topic ASC 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. By the end of the first quarter of 2024, we finalized the allocation of the purchase price to specific assets and liabilities. It was based on the fair value of the final consideration and the conclusion of the fair value determination of long-lived assets and all other assets acquired and liabilities assumed.

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant and internally generated price assumptions, production profiles and operating and development cost assumptions. The fair values of other assets acquired and liabilities assumed, which included accounts receivable, accounts payable, and most other current assets and current liabilities, were determined to be equivalent to the carrying value due to their short-term nature. The total consideration of $ billion was allocated to the identifiable assets and liabilities based on their fair values as of the acquisition date of October 4, 2023.

Asset retirement obligations()Other()Total identifiable net assets$

With the completion of the transaction, we acquired proved and unproved properties of approximately $ billion and $ billion, respectively.

In anticipation of the acquisition, we entered into, and settled, various foreign exchange forward contracts to purchase CAD. For the year ended December 31, 2023, we recognized a loss of $ million in the "Foreign currency transaction (gain) loss" line on our consolidated income statement associated with these forward contracts. The related cash flows are included within "Cash Flows From Investing Activities" on our consolidated statement of cash flows.

From the acquisition date through December 31, 2023, "Total Revenues and Other Income" and "Net Income (Loss)" associated with the acquired assets were $ million and $ million, respectively.


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Net Income (Loss) Earnings per share:Basic net income (loss)$ Diluted net income (loss) Millions of DollarsYear Ended December 31, 2023As reportedPro forma SurmontPro forma Marathon OilPro forma CombinedTotal Revenues and Other Income$ Net Income (Loss) Earnings per share:Basic net income (loss)$ Diluted net income (loss) Millions of DollarsYear Ended December 31, 2022As reportedPro forma SurmontPro forma CombinedTotal Revenues and Other Income$ Exploratory well costs capitalized for a period greater than one year Ending balance$ Number of projects with exploratory well costs capitalized for a period greater than one year

West Willow—Alaska(2)

PL891—Norway(2)

Narwhal Trend—Alaska(1)

Montney—Canada(2)

Other of $10 million or less each(1)(2)

Total$

(1)Appraisal drilling complete; costs being incurred to assess development.


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million before-tax as dry hole expenses, which included $ million for partner operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea, and $ million for the Busta suspended discovery well on license PL782S in the North Sea.

2023

In our Europe, Middle East and North Africa segment, after further evaluation we recognized a before-tax expense of $ million for dry hole costs associated with the suspended Warka discovery well, drilled in 2020, on license PL1009 in the Norwegian Sea.

In our Alaska segment, we recorded a before-tax expense of approximately $ million for dry hole costs associated with the Bear-1 exploration well.

2022

In the fourth quarter, we recorded a before-tax expense of $ million for impairment of certain aged, suspended wells associated with Surmont in our Canada segment.

In our Europe, Middle East and North Africa segment, we recorded a before-tax expense of $ million for dry hole costs associated with four operated exploration and appraisal wells and one partner-operated well that were drilled in Norway in 2022.


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Accrued environmental costs Total asset retirement obligations and accrued environmental costs Asset retirement obligations and accrued environmental costs due within one year*()()Long-term asset retirement obligations and accrued environmental costs$

*Classified as a current liability on the balance sheet under “Other accruals.”

Asset Retirement Obligations

We record the fair value of a liability for an ARO when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset. If in subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Changes to estimated liabilities for assets that are no longer producing are recorded as impairment.

We have numerous AROs we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska.

Accretion of discount New obligations, including acquisitions Changes in estimates of existing obligations Spending on existing obligations()()Property dispositions()()Foreign currency translation()()

Balance at December 31

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2024 and 2023, were $ million and $ million, respectively.

We had accrued environmental costs of $ million and $ million at December 31, 2024 and 2023, respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other $ million and $ million of environmental costs associated with sites no longer in operation at December 31, 2024 and 2023, respectively. In addition, December 31, 2024 and 2023, included a $ million and $ million accrual, respectively, where the company has been named a potentially responsible party under the CERCLA, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to years.

Expected expenditures for environmental obligations acquired in various business combinations are discounted using a weighted-average percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $ million at December 31, 2024. The total expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are $ million.


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% Notes due 2024

% Notes due 2025

% Debentures due 2025

% Notes due 2025

% Debentures due 2026

% Debentures due 2027

% Notes due 2027

% Notes due 2028

% Debentures due 2029

% Notes due 2029

% Notes due 2030

% Notes due 2031

% Notes due 2032

% Notes due 2033

% Notes due 2034

% Notes due 2035

% Notes due 2036

% Notes serially maturing 2022 through 2037

% Notes due 2037

% Notes due 2038

% Notes due 2039

% Notes due 2042

% Notes due 2044

% Notes due 2045

% Notes due 2046

% Debentures due 2047

% Notes due 2047

% Notes due 2048

% Notes due 2052

% Notes due 2053

% Notes due 2054

% Notes due 2055

% Notes due 2062

% Notes due 2063

% Notes due 2065


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% – % during 2024 and % – % during 2023

Industrial Development Bonds due 2035 at % – % during 2024 and % – % during 2023

St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds due 20371: $ at %, $ at %, $ at %, $ at %1

Other Debt at face value Finance leases Net unamortized premiums, discounts and debt issuance costs()()Total debt Short-term debt()()Long-term debt$

1Future mandatory purchase dates for these bonds: July 1, 2026 for the % bonds of $ million, % bonds of $ million, % bonds of $ million and July 3, 2028 for the % bonds of $ million. Subsequent to the mandatory purchase dates, we will also have the right to remarket

these bonds any time up to the 2037 maturity date.

The principal amounts of long-term debt, excluding finance lease obligations, maturing in 2025 through 2029 are: $ million, $ million, $ million, $ million and $ million, respectively.

2024

In the fourth quarter of 2024, we acquired Marathon Oil and assumed its outstanding debt upon close. Shortly thereafter, we launched and completed concurrent debt transactions consisting of: tender offers to repurchase certain existing Marathon Oil and ConocoPhillips debt for cash (with priority for Marathon Oil debt assumed), an obligor exchange offer to retire certain Marathon Oil debt in exchange for new ConocoPhillips debt, new debt issuances to fund the repurchase tender offers and the remarketing of available municipal bonds. See Note 3.

Marathon Oil Debt Assumed at Fair Value

In November 2024, we completed the acquisition of Marathon Oil. As part of the acquisition, we assumed Marathon Oil's publicly traded debt, with an outstanding principal balance of $ billion, which was recorded at fair value of $ billion. See Note 3.

•% Notes due 2027 with principal amount of $ million

•% Notes due 2029 with principal amount of $ million

•% Notes due 2032 with principal amount of $ million

•% Notes due 2034 with principal amount of $ million

•% Notes due 2037 with principal amount of $ million

•% Notes due 2045 with principal amount of $ million

•St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds due 2037 with future mandatory purchase dates of July 1, 2026:

◦% Bonds with principal amount of $ million


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million in aggregate principal amount of debt as listed below. We paid premiums above face value of $ million to repurchase these debt instruments.

Marathon Oil Debt Repurchased:

•% Notes due 2027 partial repurchase of $ million

•% Notes due 2029 partial repurchase of $ million

•% Notes due 2032 partial repurchase of $ million

•% Notes due 2034 partial repurchase of $ million

•% Notes due 2037 partial repurchase of $ million

•% Notes due 2045 partial repurchase of $ million

ConocoPhillips Debt Repurchased:

•% Debentures due 2027 with principal amount of $ million (partial repurchase of $ million)

•% Debentures due 2029 with principal amount of $ million (partial repurchase of $ million)

•% Notes due 2029 with principal amount of $ million (partial repurchase of $ million)

•% Notes due 2030 with principal amount of $ million (partial repurchase of $ million)

•% Notes due 2031 with principal amount of $ million (partial repurchase of $ million)

Exchange Offer

Concurrently in December 2024, we completed a debt exchange offer through which $ million in aggregate principal of existing Marathon Oil notes were tendered and accepted in exchange for $ million of new ConocoPhillips notes. The debt exchange offers were treated as debt modifications for accounting purposes resulting in a portion of the unamortized debt discount and premiums of the existing notes being allocated to the new notes on the settlement dates of the exchange offers. No premiums were paid to bondholders in this exchange offer.

The notes tendered and accepted in the exchange offers were:

•% Notes due 2027 partial exchange of $ million

•% Notes due 2029 partial exchange of $ million

•% Notes due 2032 partial exchange of $ million

•% Notes due 2034 partial exchange of $ million

•% Notes due 2037 partial exchange of $ million

•% Notes due 2045 partial exchange of $ million

New Debt Issuance

In December 2024, we issued new debt of $ billion through our universal shelf registration statement and prospectus supplement consisting of the following new notes and used the proceeds to repurchase existing debt as discussed:

•% Notes due 2030 with principal of $ million

•% Notes due 2032 with principal of $ million

•% Notes due 2035 with principal of $ million

•% Notes due 2055 with principal of $ million

•% Notes due 2065 with principal of $ million

Municipal Bonds Reoffering and Issuance

We completed a $ million remarketing of sub-series 2017C bonds that are part of the $ billion St. John the Baptist Parish, State of Louisiana—Revenue Refunding Bonds Series 2017. The bonds are subject to an interest rate of % and a mandatory purchase date of July 3, 2028.

As a result of the concurrent debt transactions as described above, we recognized a net loss on debt extinguishments of $ million which is included in the "Other expenses" line on our consolidated income statement.

Other Debt Activity

Apart from the concurrent debt transactions discussed above, in November 2024, the company retired $ million principal amount of our % Notes at maturity and in March 2024, the company retired $ million principal amount of our % Notes at maturity.


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million principal amount of our percent Notes at maturity. In the third quarter of 2023, we issued $ billion in new Notes through our universal shelf registration statement and prospectus supplement. The net proceeds were used to fund the acquisition of the remaining percent working interest in Surmont which closed in October 2023. See Note 3. The following Notes were issued:

•% Notes due 2033 with principal of $ billion

•% Notes due 2054 with principal of $ billion

•% Notes due 2063 with principal of $ billion

In the second quarter of 2023, as described further below, we initiated and completed two concurrent transactions as part of our debt refinancing strategy. We issued $ billion in new Notes through our universal shelf registration statement and prospectus supplement and used the proceeds to repurchase $ billion of existing debt.

Debt Issuance

On May 23, 2023, we issued % Notes due 2053 with principal of $ billion.

Repurchase Tender Offers

On May 25, 2023, we repurchased a total of $ million aggregate principal amount of debt as listed below. We paid $ million below face value to repurchase these debt instruments and recognized a gain on debt extinguishment of $ million, which is included in the "Other expenses" line on our consolidated income statement.

•% Notes due 2024 with principal of $ million (partial repurchase of $ million)

•% Notes due 2025 with principal of $ million (partial repurchase of $ million)

Revolving Credit Facility and Credit Rating Information

We have a revolving credit facility totaling $ billion with an expiration date of February 2027. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $ 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 $ 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 facility agreement calls for commitment fees on available, but unused, amounts. The facility 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 our ability to issue up to $ billion of commercial paper. Commercial paper is generally limited to maturities of 90 days and is included in short-term debt on our consolidated balance sheet. With no commercial paper outstanding and direct borrowings or letters of credit, we had access to $ billion in available borrowing capacity under our revolving credit facility at December 31, 2024 and December 31, 2023.

For information on Finance Leases, see Note 14.

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

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 ratings 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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million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis, therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing December 2024 exchange rates:

•During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee to be . Our maximum exposure under this guarantee is approximately $ million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At December 31, 2024, the carrying value of this guarantee was approximately $ million.

•In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy Limited in October 2008, we agreed to reimburse Origin Energy Limited for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements. The final guarantee expires in the fourth quarter of 2041. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $ million ($ billion in the event of intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

•We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of to years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $ million and would become payable if APLNG does not perform. At December 31, 2024, the carrying value of these guarantees was approximately $ million.

QatarEnergy LNG Limited Guarantee

We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in NFE4 and NFS3. This guarantee has an approximate -year term with no maximum limit. At December 31, 2024, the carrying value of this guarantee was approximately $ million.

Equatorial Guinea Guarantees

We have guaranteed payment obligations as a shareholder in both Equatorial Guinea LNG Operations, S.A., a fully owned subsidiary of Equatorial Guinea LNG Holdings Limited, and Alba Plant LLC with regard to certain agreements to process third-party gas. These guarantees have remaining, and the maximum potential future payments related to these guarantees is approximately $ million. At December 31, 2024, the carrying value of these guarantees was approximately $ million.


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million, which consist primarily of guarantees of the residual value of leased office buildings and guarantees of the residual value of corporate aircraft. These guarantees have remaining terms of one to and would become payable if certain asset values are lower than guaranteed amounts at the end of the lease or contract term, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties. At December 31, 2024, there was carrying value associated with these guarantees.

Indemnifications

million. Those related to environmental issues have terms that are generally indefinite and the maximum amounts of future payments are generally unlimited. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. See Note 10


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million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, the government of Venezuela expropriated ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures, as well as the offshore Corocoro development project. In response, ConocoPhillips initiated international arbitration proceedings before the ICSID. In March 2019, an ICSID tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $ billion (later reduced to $ billion) plus interest for the unlawful expropriation of the projects. On January 22, 2025, an ICSID annulment committee dismissed Venezuela’s application to annul the tribunal’s decision and upheld the $ billion award plus interest in full. Separate arbitrations before the ICC resulted in additional awards against PDVSA and of its affiliates, including an award for approximately $ billion plus interest, for the Hamaca and Petrozuata projects, and a $ million award, for the Corocoro project, plus interest. As of December 31, 2024, the company has received approximately $ million in connection with the first ICC award. Collection actions for all awards are ongoing.

ConocoPhillips has ensured that all actions related to these arbitration awards meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.


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offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease P-0166 relinquished the lease and abandoned the lease platforms and facilities. BSEE’s order to ConocoPhillips is premised on its connection to Phillips Petroleum Company, a legacy company of ConocoPhillips, which held a historical percent interest in this lease and operated these facilities but sold its interest over years ago. ConocoPhillips continues to evaluate its exposure in this matter.

In July 2021, a federal securities class action was filed against Concho, certain of Concho’s officers, and ConocoPhillips as Concho’s successor in the United States District Court for the Southern District of Texas. On October 21, 2021, the court issued an order appointing Utah Retirement Systems and the Construction Laborers Pension Trust for Southern California as lead plaintiffs (Lead Plaintiffs). On January 7, 2022, the Lead Plaintiffs filed their consolidated complaint alleging that Concho made materially false and misleading statements regarding its business and operations in violation of the federal securities laws and seeking unspecified damages, attorneys’ fees, costs, equitable/injunctive relief and such other relief that may be deemed appropriate. The defendants filed a motion to dismiss the consolidated complaint on March 8, 2022. On June 23, 2023, the court denied defendants’ motion as to most defendants including Concho/ConocoPhillips. We believe the allegations in the action are without merit and are vigorously defending this litigation.

ConocoPhillips is involved in pending disputes with commercial counterparties relating to the propriety of its force majeure notices following Winter Storm Uri in 2021. We believe these claims are without merit and are vigorously defending them.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation and LNG purchase commitments. The fixed and determinable portion of the remaining estimated payments under these various agreements as of December 31, 2024 are: 2025—$ million; 2026—$ million; 2027—$ million; 2028—$ million; 2029—$ million; and 2030 and after—$ billion. Generally, variable components of these obligations include commodity futures prices and inflation rates. Purchases of LNG under these commitments are expected to be offset in the same or approximately same periods by cash received from the related sales transactions. Total payments under these agreements were $ million in 2024, $ million in 2023 and $ million in 2022.


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Other assets LiabilitiesOther accruals Other liabilities and deferred credits ()Other income()()()Purchased commodities()()())()Basis ()


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percent of the projected term loans outstanding to finance the cost of development and construction of Phase 1 from floating to fixed rate. These swaps were designated and qualified for hedge accounting under ASC Topic 815, “Derivatives and Hedging,” as a cash flow hedge with changes in the fair value of the designated hedging instruments reported as a component of other comprehensive income and to be reclassified into earnings in the same periods that the hedged transactions will affect earnings.

In 2024, PALNG de-designated a portion of the interest rate swaps as a cash flow hedge. Changes in the fair value of the de-designated hedging instruments are reported in the "Equity in earnings of affiliates" line on our consolidated income statement.

For the years ended December 31, 2024, and 2023, we recognized an unrealized loss of $ million and an unrealized gain of $ million in other comprehensive income, respectively, related to the hedge accounted swaps. For the year ended December 31, 2024, we recognized $ million in "Equity in earnings of affiliates" related to the de-designated swaps.

Financial Instruments

We invest in financial instruments with maturities based on our cash forecasts for the various accounts and currency pools we manage. The types of financial instruments in which we currently invest include:

•Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of time.

•Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be withdrawn without notice.

•Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.

•U.S. government or government agency obligations: Securities issued by the U.S. government or U.S. government agencies.

•Foreign government obligations: Securities issued by foreign governments.

•Corporate bonds: Unsecured debt securities issued by corporations.

•Asset-backed securities: Collateralized debt securities.

Demand Deposits Time Deposits

1 to 90 days

91 to 180 days

Within one year U.S. Government Obligations

1 to 90 days


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Commercial Paper U.S. Government Obligations

U.S. Government Agency Obligations

Foreign Government Obligations Asset-backed Securities $

Cash and cash equivalents and Short-term investments have remaining maturities within one year. Investments and long-term receivables have remaining maturities that vary from greater than one year through four years.

Commercial Paper U.S. Government Obligations U.S. Government Agency Obligations Foreign Government Obligations Asset-backed Securities $

As of December 31, 2024, total unrealized gains for debt securities classified as available for sale with net gains were $ million and total unrealized losses for debt securities classified as available for sale with net losses were $ million. As of December 31, 2023, total unrealized gains for debt securities classified as available for sale with net unrealized gains were $ million. allowance for credit losses has been recorded on investments in debt securities which are in an unrealized loss position.

For the years ended December 31, 2024 and 2023, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $ million and $ million, respectively. Gross realized gains and losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and redeemed is determined using the specific identification method.


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days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We may require collateral to limit the exposure to loss, including letters of credit, prepayments and surety bonds, as well as master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position at December 31, 2024 and December 31, 2023, was $ million and $ million, respectively. For these instruments, collateral was posted at December 31, 2024 and December 31, 2023. If our credit rating had been downgraded below investment grade at December 31, 2024, we would have been required to post $ million of additional collateral, either with cash or letters of credit.


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percent working interest in Surmont. Contingent consideration consists of payments up to approximately $ billion CAD over a term ending in the fourth quarter of 2028. The contingent payments represent $ million for every dollar that the monthly WCS average pricing exceeds $ per barrel. The terms include adjustments related to not achieving certain production targets. The fair value of the contingent consideration as of December 31, 2024 is calculated using the income approach and is largely based on the estimated commodity price outlook using a combination of external pricing service companies' and our internal price outlook (unobservable input) and a discount rate consistent with those used by principal market participants (observable input). Impact of other unobservable inputs on the fair value as of December 31, 2024 was not significant. Commodity derivatives Total assets$ LiabilitiesCommodity derivatives$ Contingent consideration Total liabilities$


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Discounted cash flowCommodity price outlook* ($/BOE)

$ - $ ($)

December 31, 2023

$ - $ ($)

*Commodity price outlook based on a combination of external pricing service companies' outlooks and our internal outlook.

Liabilities December 31, 2023Assets$ Liabilities

At December 31, 2024 and December 31, 2023, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Reported Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

•Cash and cash equivalents and short-term investments: The carrying amount reported on the balance sheet approximates fair value. For those investments classified as available for sale debt securities, the carrying amount reported on the balance sheet is fair value.

•Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value.

•Investments in debt securities classified as available for sale: The fair value of investments in debt securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using pricing provided by brokers or pricing service companies that are corroborated with market data. See Note 11.

•Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.

•Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

•Commercial paper: The carrying amount of our commercial paper instruments approximates fair value and is reported on the balance sheet as short-term debt.


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Investments in debt securities Financial liabilitiesTotal debt, excluding finance leases Commodity derivatives

Acquisition of Marathon Oil Distributed under benefit plans End of year Held in TreasuryBeginning of year Repurchase of common stock End of year

Preferred Stock

We have authorized million shares of preferred stock, par value $ per share, of which was issued or outstanding at December 31, 2024 or 2023.

Repurchase of Common Stock

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 $ billion by a total of the lesser of $ billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $ billion in aggregate purchases. Since inception of our current program, shares repurchased totaled million shares at a cost of $ billion through the end of December 2024.

million CVE common shares.


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Accumulated DD&A()()

Net PP&E*

Other assets Lease Liabilities

Short-term debt**

Other accruals

Long-term debt***

Other liabilities and deferred credits Total lease liabilities$

* Includes proportionately consolidated finance lease assets of $ million at December 31, 2024 and $ million at December 31, 2023.

** Includes proportionately consolidated finance lease liabilities of $ million at December 31, 2024 and $ million at December 31, 2023.

million at December 31, 2024 and $ million at December 31, 2023.

Finance lease costAmortization of right-of-use assets Interest on lease liabilities

Short-term lease cost**

Total lease cost***

$ * The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.

** Short-term leases are not recorded on our consolidated balance sheet.

*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above.

Finance leasesWeighted-average discount rate (percent)Operating leases Finance leases


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Operating cash flows from finance leases Financing cash flows from finance leases Right-of-use assets obtained in exchange for operating lease liabilities$ Right-of-use assets obtained in exchange for finance lease liabilities

*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.

2026 2027 2028 2029 Remaining years

Total

Less: portion representing imputed interest()()Total lease liabilities$ $


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Service cost Interest cost Plan participant contributions Plan amendments Business combinations Actuarial (gain) loss()() Benefits paid()()()()()()Curtailment Recognition of termination benefits Foreign currency exchange rate change ()

Benefit obligation at December 31*

*Accumulated benefit obligation portion of above at December 31:

$ Change in Fair Value of Plan AssetsFair value of plan assets at January 1$ Actual return on plan assets Company contributions Plan participant contributions Business combinations Benefits paid()()()()()()Foreign currency exchange rate change ()

Fair value of plan assets at December 31

$ Funded Status$() () ()()


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Current liabilities()()()()()()Noncurrent liabilities()()()()()()Total recognized$() () ()()

Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31

Discount rate % Rate of compensation increase Interest crediting rate for applicable benefits

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31

Discount rate % Expected return on plan assets Rate of compensation increase Interest crediting rate for applicable benefits

For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

During 2024, the actuarial gains related to the benefit obligations for international plans were primarily related to an increase in the discount rates. During 2023, the actuarial losses related to the benefit obligations for U.S. and international plans were primarily related to a decrease in the discount rates.

Fair value of plan assets Pension Plans with Accumulated Benefit Obligation in Excess of Plan AssetsAccumulated benefit obligation$ Fair value of plan assets


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Unrecognized prior service cost (credit) ()() ()()Amortization of actuarial loss included in income (loss)* ()Net change during the period$ ()()Prior service credit (cost) arising during the period$ () Amortization of prior service (credit) included in income (loss) ()()Net change during the period$ () ()()

*Includes settlement (gains) losses recognized in 2024 and 2023.

Interest cost Expected return on plan assets()()()()()() Amortization of prior service credit ()()()()Recognized net actuarial loss (gain) () Settlements loss (gain) () Curtailment loss (gain) Net periodic benefit cost$ ()()()

The components of net periodic benefit cost, other than the service cost component, are included in the “Other expenses” line item on our consolidated income statement.


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million in 2023 and $ million in 2022 as lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of service and interest costs for those plans and led to recognition of settlement losses.

In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize percent of the unamortized balance each year.

We have multiple non-pension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, most with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of percent in 2025 that declines to percent by 2032. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of percent in 2025 that increases to percent by 2030.

Plan Assets

We follow a policy of broadly diversifying pension plan assets across asset classes and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets, aggregated across U.S. and international plans, are percent in equity securities, percent in debt securities, percent in real estate and percent in other. Generally, the plan investments are publicly traded; therefore, minimizing liquidity risk in the portfolio.

The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2024 and 2023.

•Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices in active markets for identical assets and liabilities.

•Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and quoted market prices for similar assets and liabilities in active markets and for identical assets and liabilities in markets that are not active. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable quoted market prices are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.

•Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

•Fair values of mutual funds are based on quoted market prices, which represent the net asset value of shares held.

•Time deposits are valued at cost, which approximates fair value.

•Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at the measurement date are categorized as Level 2.

•Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources.

•Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.

•Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.


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million and consisted of $ million in debt securities, less $ million for the accumulated benefit obligation covered by the contract. At December 31, 2023, the participating interest in the annuity contract was valued at $ million and consisted of $ million in debt securities, less $ million for the accumulated benefit obligation covered by the contract. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract. International Mutual funds Debt securitiesCorporate Mutual funds Private equity funds Cash and cash equivalents Insurance contracts Real estate Total in fair value hierarchy$ Investments measured at net asset value*Equity securitiesCommon/collective trusts Debt securitiesCommon/collective trusts Cash and cash equivalents Real estate Total**$

*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset of $ million and net receivables related to security transactions of $ million.


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International Mutual funds Debt securitiesCorporate Mutual funds Cash and cash equivalents DerivativesReal estate Total in fair value hierarchy$ Investments measured at net asset value*Equity securities Common/collective trusts Debt securitiesCommon/collective trusts Cash and cash equivalents Real estate Total**$

million and net receivables related to security transactions of $ million.

Level 3 activity was not material for all periods.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2025, we expect to contribute approximately $ million to our domestic qualified and nonqualified pension and postretirement benefit plans and $ million to our international qualified and nonqualified pension and postretirement benefit plans.


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2026 2027 2028 2029 2030–2034 Accruals Benefit payments()()()

Balance at December 31

In 2024, accruals included severance costs associated with contractual termination benefits applicable to officers and employees of Marathon Oil as of the acquisition date. Of the remaining balance at December 31, 2024, $ million is classified as short-term. See Note 3.

Defined Contribution Plans

Most U.S. employees are eligible to participate in a defined contribution plan. Company contributions can vary based on employee compensation and contribution elections, whether the employee is accruing benefits in a defined benefit plan and company discretion. Company contributions charged to expense for U.S. defined contribution plans were $ million in 2024, $ million in 2023 and $ million in 2022.

We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $ million in 2024, $ million in 2023 and $ million in 2022.

Share-Based Compensation Plans

The 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (Omnibus Plan) was approved by shareholders in May 2023, replacing similar prior plans and providing that no new awards shall be granted under the prior plans. Over its life, the Omnibus Plan allows the issuance of up to million shares of our common stock for compensation to our employees and directors, but the available shares (i) are reduced by awards granted under the prior plan between the board adoption date (February 15, 2023) and the shareholder approval date (May 16, 2023) and (ii) are increased by any shares of common stock represented by awards granted under the Omnibus Plan or the prior plans that are forfeited, expire or are cancelled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company, excluding shares surrendered in payment of the exercise of a stock option or stock appreciation right, shares not issued in connection with the stock settlement of a stock appreciation right, or shares reacquired by the company using cash proceeds from the exercise of a stock option. The Human Resources and Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, RSUs and performance share units (PSU) to employees and non-employee directors who contribute to the company’s continued success and profitability.


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Tax benefit

Stock Options—Stock options granted under the provisions of the Omnibus Plan and prior plans permit purchase of our common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock on the date the options were granted. The options have terms of years and generally vest ratably on the first, second and third anniversaries of the date of grant. Options awarded to certain employees already eligible for retirement vest within of the grant date, but those options do not become exercisable until the end of the normal vesting period. Beginning in 2018, stock option grants were discontinued.

$ $ Exercised() Expired or cancelled

Outstanding at December 31, 2024

$ $

Vested at December 31, 2024

$ $

Exercisable at December 31, 2024

$ $

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2024, were all years. The aggregate intrinsic value of options exercised was $ million in 2023 and $ million in 2022.

During 2024, we received $ million in cash and realized a tax benefit of $ million from the exercise of options. At December 31, 2024, all outstanding stock options were fully vested and there was no remaining compensation cost to be recorded.

Stock Unit Programs—RSUs granted annually under the provisions of the Omnibus Plan and the general and executive RSU programs vest in installment on the third anniversary of the grant date. RSUs granted under the Omnibus Plan for a variable long-term incentive retention program vest ratably on the first, second and third anniversaries of the grant date. RSUs are also granted ad hoc to attract or retain key personnel, or assumed as a result of an acquisition, and the terms and conditions under which these RSUs vest vary by award.


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$ Granted Forfeited() Issued() $

Outstanding at December 31, 2024

Not Vested at December 31, 2024

At December 31, 2024, the remaining unrecognized compensation cost from the unvested stock-settled RSUs was $ million, which will be recognized over a weighted-average period of years, the longest period being 3 years. The weighted-average grant date fair value of stock-settled RSUs granted during 2023 and 2022 was $ and , respectively. The total fair value of stock-settled RSUs issued during 2023 and 2022 was $ million and $ million, respectively.

Cash-Settled

Cash-settled executive RSUs granted in 2018 and 2019 replaced the stock option program. These RSUs, subject to elections to defer, were settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. Executive RSUs awarded to retirement eligible employees may vest earlier; however, those units were not settled until after the earlier of separation from the company or the end of the regularly scheduled vesting period. Compensation expense was initially measured using the average fair market value of ConocoPhillips common stock and was subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the settlement date. Recipients received an accrued reinvested dividend equivalent that was charged to compensation expense. The accrued reinvested dividend was paid at the time of settlement, subject to the terms and conditions of the award.

There was no cash-settled stock unit activity and no remaining unrecognized compensation cost to be recorded for the unvested cash-settled units for the year ended December 31, 2024 and December 31, 2023. The total fair value of cash-settled executive RSUs issued during 2022 was $ million.

Performance Share Program—Under the Omnibus Plan, we also annually grant restricted PSUs to senior management. These PSUs are authorized prior to their effective grant date (the performance period). Compensation expense is initially measured using the average fair market value of ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the grant date for stock-settled awards and the settlement date for cash-settled awards.


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of service, and restrictions do not lapse until the employee separates from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with of service or after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or after the grant date (although recipients can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Because these awards are authorized prior to the effective grant date, for employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Until issued as stock, recipients of the stock-settled PSUs issued prior to 2013 receive a cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, stock-settled PSUs authorized for future grants will vest upon settlement following the conclusion of the performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. Until issued as stock, recipients of these PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense.

$ Granted Forfeited Issued() $

Outstanding at December 31, 2024

At December 31, 2024, there was remaining unrecognized compensation cost to be recorded on the unvested stock-settled performance shares. The weighted-average grant date fair value of stock-settled PSUs granted during 2023 and 2022 was $ and $, respectively. The total fair value of stock-settled PSUs issued during 2023 and 2022 was $ million and $ million, respectively.

Cash-Settled

In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new cash-settled PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent employee election to defer, on the earlier of after the grant date of the award or the date the employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on the balance sheet. Until settlement occurs, recipients of the PSUs receive a cash payment of a dividend equivalent that is charged to compensation expense.

Beginning in 2013, cash-settled PSUs vest upon settlement following the conclusion of the performance period. We recognize compensation expense over the period beginning on the date of authorization and ending at the conclusion of the performance period. These PSUs will be settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. For performance periods beginning before 2018, during the performance period, recipients of the PSUs do not receive a cash payment of a dividend equivalent, but after the performance period ends, until settlement in cash occurs, recipients of the PSUs receive a cash payment of a dividend equivalent that is charged to compensation expense. For the performance periods beginning in 2018 or later, recipients of the PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of settlement, subject to the terms and conditions of the award.


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$ Granted Settled() $

Outstanding at December 31, 2024

At December 31, 2024, all outstanding cash-settled performance awards were fully vested and there was remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs granted during 2023 and 2022 was $ and $, respectively. The total fair value of cash-settled performance share awards settled during 2023 and 2022 was $ million and $ million, respectively.

From inception of the Performance Share Program through 2013, approved PSU awards were granted after the conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the beginning of new performance periods. These initial target PSU awards will terminate at the end of the performance periods and will be settled after the performance periods have ended. Also in 2014, initial target PSU awards were issued for open performance periods that began in prior years. For the open performance period beginning in 2012, the initial target PSU awards terminated at the end of the performance period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the initial target PSU awards terminated at the end of the performance period and were settled after the performance period ended. There is no effect on recognition of compensation expense.

Other—In addition to the above active programs, we have outstanding shares of restricted stock and RSUs that were either issued as part of our non-employee director compensation program for current and former members of the company’s Board of Directors or as part of an executive compensation program that has been discontinued or assumed as a result of an acquisition. Generally, the recipients of the restricted shares or units receive a dividend or dividend equivalent.

$ Granted Cancelled Issued() $

Outstanding at December 31, 2024

and $, respectively. The total fair value of awards issued during 2023 and 2022 was $ million and $ million, respectively.


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Deferred ForeignCurrent Deferred State and localCurrent Deferred Total tax provision (benefit)$ Inventory Other Total deferred tax liabilities Deferred Tax AssetsBenefit plan accruals Asset retirement obligations and accrued environmental costs Investments in joint ventures Other financial accruals and deferrals Loss and credit carryforwards Other Total deferred tax assets Less: valuation allowance()()Total deferred tax assets net of valuation allowance Net deferred tax liabilities$

At December 31, 2024, noncurrent assets and liabilities included deferred taxes of $ million and $ million, respectively. At December 31, 2023, noncurrent assets and liabilities included deferred taxes of $ million and $ million, respectively.

Our deferred tax liability increased during 2024 by $ billion due to the acquisition of Marathon Oil.

At December 31, 2024, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $ billion and various jurisdictions net operating loss and credit carryforwards of $ billion. In 2024, $ billion of U.S. foreign tax credits expired. This reduction was partly offset by an increase of $ million in our U.S. net operating loss, foreign tax credit carryforwards, and other credit carryforwards due to our acquisition of Marathon Oil. See Note 3.

At December 31, 2023, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $ billion and various jurisdictions net operating loss and credit carryforwards of $ billion.


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Charged to expense (benefit)()() Other*()()()

Balance at December 31

*Represents changes due to deferred tax assets that have no impact to our effective tax rate, acquisitions/dispositions/revisions and the effect of translating foreign financial statements.

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. At December 31, 2024, we have maintained a valuation allowance with respect to substantially all U.S. foreign tax credit carryforwards, basis differences in our APLNG investment, and certain net operating loss carryforwards for various jurisdictions. During 2024, the valuation allowance movement charged to earnings primarily relates to the ability to utilize a portion of ConocoPhillips foreign tax credit carryforwards due to the acquisition of Marathon Oil. During 2022, the valuation allowance movement charged to earnings primarily related to the impact of 2022 changes to Norway’s Petroleum Tax System which is partly offset by the U.S. tax impact of the disposition of our CVE common shares. Other movements are primarily related to valuation allowances on expiring tax attributes. Based on our historical taxable income, expectations for the future and available tax-planning strategies, management expects deferred tax assets, net of valuation allowances, will primarily be realized as offsets to reversing deferred tax liabilities. See Note 3.

As a result of the acquisition of Marathon Oil, we utilized foreign tax credits previously offset by a valuation allowance. During the fourth quarter of 2024, a tax benefit of $ million was recorded as a result of the acquisition and the subsequent utilization of the foreign tax credits. See Note 3.

During the second quarter of 2022, Norway enacted changes to the Petroleum Tax System. As a result of the enactment, a valuation allowance of $ million was recorded during the second quarter to reflect changes to our ability to realize certain deferred tax assets under the new law.

At December 31, 2024, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $ million. Deferred income taxes have not been provided on this amount, as we do not plan to initiate any action that would require the payment of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be payable on this income if distributed is approximately $ million.

Additions based on tax positions related to the current year Additions for tax positions of prior years Reductions for tax positions of prior years ()()Settlements()()()Lapse of statute()()()

Balance at December 31

Included in the balance of unrecognized tax benefits for 2024, 2023 and 2022 were $ million, $ million and $ million, respectively, which, if recognized, would impact our effective tax rate.


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million as well as the closing of our 2018 Canadian domestic audit that resulted in a reduction of $ million.

The balance of the unrecognized tax benefits decreased in 2022 due to the closing of the 2017 audit of our federal income tax return. As a result, we recognized federal and state tax benefits totaling $ million relating to the recovery of outside tax basis previously offset by a full reserve.

At December 31, 2024, 2023 and 2022, accrued liabilities for interest and penalties totaled $ million, $ million and $ million, respectively, net of accrued income taxes. Interest and penalties resulted in an increase to earnings of $ million in 2024, a reduction to earnings of $ million in 2023 and an increase to earnings of $ million in 2022.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: Canada (2016), Norway (2023) and U.S. (2019). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. Consequently, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. Within the next twelve months, we may have audit periods close that could significantly impact our total unrecognized tax benefits. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

% Foreign $ % Federal statutory income tax$ % Non-U.S. effective tax rates Recovery of outside basis()()() ()Adjustment to tax reserves()()()()()()Adjustment to valuation allowance()() () State income tax Other ()() ()()Total$ %

Our effective tax rate for 2024 was driven by our jurisdictional tax rates for this profit mix with a favorable impact from the acquisition of Marathon Oil enabling the utilization of foreign tax credits previously offset by a valuation allowance. See Note 3.

Our effective tax rate for 2023 was driven by our jurisdictional tax rates for this profit mix with a favorable impact from routine tax credits. The adjustment to tax reserves primarily relates to the lapsing of the statute of limitations on certain of our foreign subsidiaries and the closing of the 2018 Canadian domestic audit.

Our effective tax rate for 2022 was driven by our jurisdictional tax rates for this profit mix with net favorable impacts from routine tax credits and valuation allowance adjustments. The adjustment to tax reserves primarily relates to the closing of the audit of our 2017 U.S. federal tax return and the recognition of the U.S. federal and state tax benefits described above.


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Purchases Operating expenses and selling, general and administrative expenses Net interest (income)/loss* ()

*We paid interest to, or received interest from, various affiliates. See Note 4 for additional information on loans to affiliated companies.

Revenue from contracts outside the scope of ASC Topic 606Physical contracts meeting the definition of a derivative Financial derivative contracts()() Consolidated sales and other operating revenues$

Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices, which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 23—Segment Disclosures and Related Information:


	Millions of Dollars
	2024	2023	2022
Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment
Lower 48	$
Canada
Europe, Middle East and North Africa
Physical contracts meeting the definition of a derivative	$


	Millions of Dollars
	2024	2023	2022
Revenue from Contracts Outside the Scope of ASC Topic 606 by Product
Crude oil	$
Natural gas
Other
Physical contracts meeting the definition of a derivative	$


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million compared with $ million at December 31, 2023, and included both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical natural gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with natural gas sold under contracts for which NPNS has not been elected compared with trade receivables where NPNS has been elected.

Contract Liabilities from Contracts with Customers

We have entered into certain agreements under which we license our proprietary technology, including the Optimized Cascade® process technology, to customers to maximize the efficiency of LNG plants. These agreements typically provide for milestone payments to be made during and after the construction phases of the LNG plant. The payments are not directly related to our performance obligations under the contract and are recorded as deferred revenue to be recognized when the customer is able to benefit from their right to use the applicable licensed technology. Revenue recognized during the year ended December 31, 2024 was . We expect to recognize the outstanding contract liabilities of $ million as of December 31, 2024, as revenue during the years 2026, 2028 and 2029.


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Notes to Consolidated Financial Statements			Table of Contents

Less: Dividends and undistributed earningsallocated to participating securities Net Income (Loss) available to common shareholders$ Average common shares outstanding (in Millions) Net Income (Loss) Per Share of Common Stock$ Diluted earnings per shareNet Income (Loss) available to common shareholders$ Average common shares outstanding (in Millions) Add: Dilutive impact of options and unvestednon-participating RSU/PSUs Average diluted shares outstanding (in Millions) Net Income (Loss) Per Share of Common Stock$

operating segments, which are primarily defined by geographic region: Alaska; Lower 48 (L48); Canada; Europe, Middle East and North Africa (EMENA); Asia Pacific (AP); and Other International (OI).

Corporate and Other (Corporate) represents income and costs not directly associated with an operating segment, such as most interest expense, premiums on early retirement of debt, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

Our chief operating decision maker (CODM) is our Chairman of the Board of Directors and Chief Executive Officer, who evaluates performance and allocates resources among our operating segments based on each segment's net income (loss). This is done through the annual budget and forecasting process.

Segment accounting policies are the same as those in Note 1. Intersegment sales are at prices that approximate market.


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Notes to Consolidated Financial Statements			Table of Contents

Intersegment eliminations ()() ()()Consolidated sales and other operating revenues* Significant segment expenses**Production and operating expenses DD&A Income tax provision (benefit) ()() Total ()() Other segment itemsEquity in earnings of affiliates () ()() ()()Interest income () ()()

Impairments: Alaska, L48, Canada and EMENA

Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate

Foreign currency transaction (gain) loss: Canada, EMENA and Corporate

Other expenses: Alaska, L48, EMENA and Corporate

Total Assets Capital expenditures and investments


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Notes to Consolidated Financial Statements			Table of Contents

Intersegment eliminations ()() ()()Consolidated sales and other operating revenues* Significant segment expenses**Production and operating expenses DD&A Income tax provision (benefit) () Total () Other segment itemsEquity in earnings of affiliates() ()() ()Interest income ()() ()()Interest and debt expense Other*** Total () Net income (loss)$ ()()

*In 2023, sales by our Lower 48 segment to a certain pipeline company accounted for approximately $ billion or approximately percent of our total consolidated sales and other operating revenues.

**The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.***Other segment items not required to be separately disclosed for each reportable segment include:

Gain (loss) on dispositions: Alaska, L48, AP, OI and Corporate

Other income; Purchased commodities; Selling, general and administrative expenses and Exploration expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate

Impairments: L48, Canada and Corporate

Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate

Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate

Other expenses: Alaska, L48, EMENA and Corporate

Total Assets Capital expenditures and investments


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Notes to Consolidated Financial Statements			Table of Contents

Intersegment eliminations ()()() ()()Consolidated sales and other operating revenues* Significant segment expenses**Production and operating expenses DD&A Income tax provision (benefit) () Total () Other segment itemsEquity in earnings of affiliates() ()()() ()Interest income ()() ()()Interest and debt expense Other*** ()() Total ()() Net income (loss)$ ()() *In 2022, no single customer amounted to 10% of our total consolidated sales and other operating revenues.**The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.***Other segment items not required to be separately disclosed for each reportable segment include:

Gain (loss) on dispositions: Alaska, L48, Canada, AP, OI and Corporate

Other income: Alaska, L48, EMENA, AP, OI and Corporate

Purchased commodities: Alaska, L48, Canada, EMENA and AP

Selling, general and administrative expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate

Exploration expenses, Impairments, Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate

Foreign currency transaction (gain) loss: Canada, EMENA, AP, OI and Corporate

Other expenses: Alaska, L48, Canada, EMENA and Corporate

Total Assets Capital expenditures and investments


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Notes to Consolidated Financial Statements			Table of Contents

Natural gas Natural gas liquids Other* Consolidated sales and other operating revenues by product$

*Includes bitumen and power.

Australia Canada China Equatorial Guinea

Indonesia***

Libya Malaysia Norway Singapore U.K. Other foreign countries Worldwide consolidated$

*Sales and other operating revenues are attributable to countries based on the location of their selling operation.

** Defined as net PP&E plus equity investments and advances to affiliated companies.


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Supplementary Data			Table of Contents


Oil and Gas Operations (Unaudited)

In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC, we are making certain supplemental disclosures about our oil and gas exploration and production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report. Our disclosures by geographic area include the U.S., Canada, Europe, Asia Pacific/Middle East (inclusive of equity affiliates) and Africa.

As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for economic reasons is based on historical 12-month first-of-month average prices and current costs. This estimated date when production will end 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, which are 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. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2024, approximately three percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East and Africa geographic reporting areas, and seven percent of our total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.

Reserves Governance

The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will commence the project within a reasonable time.

Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence provided by reliable technologies exists that establishes reasonable certainty of economic producibility at greater distances. As defined by SEC regulations, reliable technologies may be used in reserve estimation when they have been demonstrated in the field to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. The technologies and data used in the estimation of our proved reserves include, but are not limited to, performance-based methods, volumetric-based methods, geologic maps, seismic interpretation, well logs, well test data, core data, analogy and statistical analysis.


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Supplementary Data			Table of Contents

We have a company-wide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our business units around the world. As part of our internal control process, each business unit’s reserves processes and controls are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geoscientists, finance personnel and a senior representative from DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm, reviews the business unit's reserves for adherence to SEC guidelines and company policy through on-site visits, teleconferences and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.

During 2024, our processes and controls used to assess over 85 percent of proved reserves as of December 31, 2024, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was the general processes and controls employed by ConocoPhillips in estimating its December 31, 2024 proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing the processes and internal controls used in the preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This individual holds a master’s degree in reservoir engineering. He is a member of the Society of Petroleum Engineers with over 20 years of oil and gas industry experience and has held positions of increasing responsibility in reservoir engineering, subsurface and asset management in the U.S. and several international field locations.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.


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Supplementary Data			Table of Contents


Proved Reserves

Years Ended December 31	Crude Oil
	Millions of Barrels
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed and Undeveloped
End of 2021	1,035	1,452	2,487	10	161	122	184	2,964	63	3,027
Revisions	(31)	24	(7)	—	31	19	(3)	40	—	40
Improved recovery	—	—	—	—	—	3	—	3	—	3
Purchases	—	6	6	—	—	—	42	48	—	48
Extensions and discoveries	15	250	265	—	8	—	—	273	35	308
Production	(64)	(193)	(257)	(2)	(25)	(22)	(13)	(319)	(5)	(324)
Sales	—	(31)	(31)	—	—	(3)	—	(34)	—	(34)
End of 2022	955	1,508	2,463	8	175	119	210	2,975	93	3,068
Revisions	(57)	126	69	1	(1)	8	10	87	1	88
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	—	2	2	—	—	—	—	2	—	2
Extensions and discoveries	219	54	273	15	3	19	—	310	—	310
Production	(64)	(202)	(266)	(3)	(23)	(22)	(17)	(331)	(5)	(336)
Sales	—	(11)	(11)	—	—	—	—	(11)	—	(11)
End of 2023	1,053	1,477	2,530	21	154	124	203	3,032	89	3,121
Revisions	5	185	190	5	(5)	15	52	257	—	257
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	23	364	387	—	—	—	25	412	—	412
Extensions and discoveries	14	29	43	9	—	—	—	52	24	76
Production	(62)	(211)	(273)	(6)	(25)	(22)	(18)	(344)	(5)	(349)
Sales	—	(3)	(3)	—	—	—	—	(3)	—	(3)
End of 2024	1,033	1,841	2,874	29	124	117	262	3,406	108	3,514


Years Ended December 31	Crude Oil
	Millions of Barrels
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed

End of 2021	912	916	1,828	4	122	98	171	2,223	63	2,286
End of 2022	867	828	1,695	5	124	102	191	2,117	58	2,175
End of 2023	790	793	1,583	7	109	91	181	1,971	54	2,025
End of 2024	767	1,122	1,889	11	101	88	208	2,297	49	2,346

Undeveloped

End of 2021	123	536	659	6	39	24	13	741	—	741
End of 2022	88	680	768	3	51	17	19	858	35	893
End of 2023	263	684	947	14	45	33	22	1,061	35	1,096
End of 2024	266	719	985	18	23	29	54	1,109	59	1,168

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.


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Supplementary Data			Table of Contents

Notable changes in proved crude oil reserves in the three years ended December 31, 2024, included:

•Revisions: In 2024, upward revisions in Lower 48 were due to development drilling of 298 million barrels and technical revisions of 28 million barrels, partially offset by downward revisions of 114 million barrels for changes in development plans, 23 million barrels due to lower prices and increasing operating costs of 4 million barrels. An upward revision of 52 million barrels in Africa was due to an increase in development plans in Libya. In the consolidated operations in Asia Pacific/Middle East, upward revisions of 15 million barrels were primarily due to the project sanction of Bohai Bay Phase 5 in China. Upward revisions of 5 million barrels in Canada were due to technical revisions. In Alaska, where future production is constrained by the Trans-Alaska Pipeline System minimum flow limit, updated total North Slope development phasing indicated that the flow limit will be reached later than previously premised, resulting in upward revisions of 22 million barrels. Further upward revisions in Alaska include development plan changes of 8 million barrels. These were partially offset by downward revisions due to increasing operating costs of 15 million barrels and 10 million barrels due to technical revisions. Downward revisions in Europe were due to technical revisions of 3 million barrels and development plan changes of 2 million barrels.

In 2023, upward revisions in Lower 48 were due to development drilling of 161 million barrels and technical revisions in the unconventional plays of 31 million barrels, partially offset by downward revisions of 52 million barrels due to lower prices and 14 million barrels for changes in development plans. An upward revision of 10 million barrels in Africa was primarily development drilling in Libya. Upward revisions of 8 million barrels in the consolidated operations in Asia Pacific/Middle East were due to technical revisions. In Alaska, where future production is constrained by the Trans-Alaska Pipeline System minimum flow limit, updated total North Slope development phasing indicated that the flow limit will be reached earlier than previously premised, resulting in downward revisions of 25 million barrels. Further downward revisions in Alaska include development plan changes of 14 million barrels, cost escalation of 13 million barrels, and 7 million barrels due to lower prices, partially offset by 2 million barrels of technical revisions.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 81 million barrels and higher prices of 33 million barrels, partially offset by increasing operating costs of 72 million barrels and technical revisions of 18 million barrels. Upward revisions in Europe were primarily due to technical revisions of 23 million barrels and 8 million barrels due to higher prices. Upward revisions of 19 million barrels in our consolidated operations in Asia Pacific/Middle East were primarily due to technical revisions.

•Purchases: In 2024, our acquisition of Marathon Oil resulted in purchases for Lower 48, as well as for Africa, representing reserves in Equatorial Guinea. Purchases in Alaska represent the acquisition of additional interest in the Kuparuk River and Prudhoe Bay units.

In 2022, crude oil reserve purchases were primarily in Africa, as a result of the acquisition of additional interest in the Libya Waha Concession.

•Extensions and discoveries: In 2024, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Alaska extensions and discoveries were primarily due to Nuna and other Western North Slope projects. Extensions and discoveries in Canada were in Montney. Extensions and discoveries in our equity affiliates were in the Middle East.

In 2023, extensions and discoveries in Alaska were driven primarily by the Willow and Nuna projects. Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in Canada and Asia Pacific/Middle East were driven primarily by Montney and Bohai Phase 4B in China, respectively.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.


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Supplementary Data			Table of Contents


Years Ended December 31	Natural Gas Liquids
	Millions of Barrels
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed and Undeveloped

End of 2021	82	546	628	5	11	—		644	33	677
Revisions	1	208	209	1	3	—		213	—	213
Improved recovery	—	—	—	—	—	—		—	—	—
Purchases	—	3	3	—	—	—		3	—	3
Extensions and discoveries	—	80	80	—	1	—		81	20	101
Production	(5)	(81)	(86)	(1)	(2)	—		(89)	(3)	(92)
Sales	—	(7)	(7)	—	—	—		(7)	—	(7)
End of 2022	78	749	827	5	13	—		845	50	895
Revisions	(1)	119	118	—	2	—		120	1	121
Improved recovery	—	—	—	—	—	—		—	—	—
Purchases	—	1	1	—	—	—		1	—	1
Extensions and discoveries	—	20	20	6	—	—		26	—	26
Production	(5)	(90)	(95)	(1)	(2)	—		(98)	(3)	(101)
Sales	—	(2)	(2)	—	—	—		(2)	—	(2)
End of 2023	72	797	869	10	13	—	—	892	48	940
Revisions	4	123	127	1	(2)	—	—	126	—	126
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	1	209	210	—	—	—	14	224	—	224
Extensions and discoveries	—	15	15	3	—	—	—	18	17	35
Production	(6)	(102)	(108)	(2)	(2)	—	—	(112)	(3)	(115)
Sales	—	(1)	(1)	—	—	—	—	(1)	—	(1)
End of 2024	71	1,041	1,112	12	9	—	14	1,147	62	1,209


Years Ended December 31	Natural Gas Liquids
	Millions of Barrels
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed

End of 2021	82	334	416	3	9	—		428	33	461
End of 2022	78	409	487	3	10	—		500	31	531
End of 2023	72	426	498	4	9	—		511	28	539
End of 2024	71	653	724	6	7	—	13	750	25	775







Undeveloped

End of 2021	—	212	212	2	2	—		216	—	216
End of 2022	—	340	340	2	3	—		345	19	364
End of 2023	—	371	371	6	4	—		381	20	401
End of 2024	—	388	388	6	2	—	1	397	37	434

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.


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Supplementary Data			Table of Contents

Notable changes in proved NGL reserves in the three years ended December 31, 2024, included:

•Revisions: In 2024, upward revisions in Lower 48 were due to additional development drilling of 164 million barrels and technical revisions of 52 million barrels. This was partially offset by development plan changes of 73 million barrels and lower prices impacting 20 million barrels.

In 2023, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 86 million barrels and technical revisions of 71 million barrels. This was partially offset by lower prices impacting 34 million barrels and development plan changes of 4 million barrels.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 88 million barrels, technical revisions of 75 million barrels, continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and NGLs) basis adding 70 million barrels, and higher prices of 13 million barrels. This was partially offset by increasing operating costs of 38 million barrels.

•Purchases: Purchases in 2024 were due to our acquisition of Marathon Oil, resulting in purchases for Lower 48 as well as in Africa, representing reserves in Equatorial Guinea.

•Extensions and discoveries: In 2024, Lower 48 extensions and discoveries were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.

In 2023, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Canada extensions and discoveries were in Montney.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Extensions and discoveries in our equity affiliates were in the Middle East.


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Supplementary Data			Table of Contents


Years Ended December 31	Natural Gas
	Billions of Cubic Feet
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed and Undeveloped

End of 2021	2,625	4,658	7,283	105	768	764	217	9,137	3,697	12,834
Revisions	(35)	361	326	8	108	(2)	(14)	426	898	1,324
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	—	23	23	—	—	—	48	71	479	550
Extensions and discoveries	—	505	505	4	103	—	—	612	1,118	1,730
Production	(88)	(543)	(631)	(23)	(117)	(51)	(10)	(832)	(439)	(1,271)
Sales	—	(262)	(262)	—	—	(385)	—	(647)	—	(647)
End of 2022	2,502	4,742	7,244	94	862	326	241	8,767	5,753	14,520
Revisions	(243)	521	278	27	73	6	(57)	327	(90)	237
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	—	4	4	—	—	—	—	4	—	4
Extensions and discoveries	—	121	121	144	1	4	—	270	58	328
Production	(84)	(570)	(654)	(25)	(113)	(24)	(12)	(828)	(446)	(1,274)
Sales	—	(97)	(97)	—	—	—	—	(97)	—	(97)
End of 2023	2,175	4,721	6,896	240	823	312	172	8,443	5,275	13,718
Revisions	102	356	458	15	47	9	3	532	(26)	506
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	47	1,177	1,224	—	—	—	310	1,534	—	1,534
Extensions and discoveries	—	87	87	67	1	—	—	155	1,075	1,230
Production	(78)	(599)	(677)	(43)	(125)	(25)	(17)	(887)	(454)	(1,341)
Sales	—	(6)	(6)	—	—	—	—	(6)	—	(6)
End of 2024	2,246	5,736	7,982	279	746	296	468	9,771	5,870	15,641


Years Ended December 31	Natural Gas
	Billions of Cubic Feet
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed

End of 2021	2,579	3,100	5,679	52	679	688	217	7,315	3,204	10,519
End of 2022	2,474	2,628	5,102	64	641	322	241	6,370	3,974	10,344
End of 2023	2,156	2,525	4,681	92	591	305	172	5,841	3,558	9,399
End of 2024	2,186	3,670	5,856	147	642	289	457	7,391	3,189	10,580







Undeveloped

End of 2021	46	1,558	1,604	53	89	76	—	1,822	493	2,315
End of 2022	28	2,114	2,142	30	221	4	—	2,397	1,779	4,176
End of 2023	19	2,196	2,215	148	232	7	—	2,602	1,717	4,319
End of 2024	60	2,066	2,126	132	104	7	11	2,380	2,681	5,061

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed in production operations. Quantities consumed in production operations are not significant in the periods presented. The value of net production consumed in operations is not reflected in net revenues and production expenses, nor do the volumes impact the respective per unit metrics.

Reserve volumes include natural gas to be consumed in operations of 2,285 BCF, 2,263 BCF and 2,416 BCF, as of December 31, 2024, 2023 and 2022, respectively. These volumes are not included in the calculation of our Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.


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Supplementary Data			Table of Contents

Notable changes in proved natural gas reserves in the three years ended December 31, 2024, included:

•Revisions: In 2024, upward revisions in Lower 48 were due to were due to additional development drilling of 841 BCF, technical revisions of 113 BCF, partly offset by downward revisions of 422 BCF for changes in development plans, 127 BCF due to lower prices and 49 BCF due to increasing operating costs. Upward revisions in Alaska of 68 BCF were due to updated total North Slope development phasing, as future production of gas is dependent on the Trans-Alaska Pipeline System minimum flow limit, which will be reached later than previously premised. Further upward revisions in Alaska included 28 BCF from revised development plans and 24 BCF to be consumed in operations. Offsetting downward revisions from technical revisions and costs were 18 BCF. In Europe, technical revisions contributed 64 BCF of upward revisions, offset by 17 BCF of development plan changes. In our equity affiliates, downward revisions were due to lower prices of 81 BCF, partially offset by positive technical revisions of 55 BCF.

In 2023, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 502 BCF, technical revisions of 268 BCF, partly offset by lower prices of 211 BCF and development plan downward revisions of 38 BCF. In Europe, technical revisions contributed 64 BCF and development drilling of 14 BCF, partially offset by lower prices of 5 BCF. In Canada, upward revisions were driven by technical revisions of 37 BCF, partially offset by lower prices of 10 BCF. In Alaska, where future production is constrained by the Trans-Alaska Pipeline System minimum flow limit, updated total North Slope development phasing indicated that the flow limit will be reached earlier than previously premised, resulting in downward revisions of 121 BCF. Further downward revisions in Alaska included 72 BCF from operating efficiencies resulting in less gas to be consumed in operations, 22 BCF due to lower prices, 14 BCF from cost escalation, and 14 BCF due to technical revisions. Downward revisions in Africa of 57 BCF due to infrastructure constraints and sales demand revisions. In our equity affiliates, downward revisions were due to lower prices of 288 BCF, offset by upward technical revisions of 198 BCF.

In 2022, upward revisions in Lower 48 were due to additional development drilling in the unconventional plays of 544 BCF, higher prices of 109 BCF, and technical revisions of 41 BCF. These were partially offset by decreases of 233 BCF due to increasing operating costs, and 100 BCF due to the continued conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and natural gas liquids) basis. Upward revisions in Canada were driven by higher prices of 26 BCF, partially offset by technical revisions of 18 BCF. In Europe, technical revisions contributed 96 BCF, and higher prices 12 BCF of upward revisions. Downward revisions in Africa were primarily due to technical revisions. In our equity affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 423 BCF, changing dynamics and improved prices in the regional LNG spot market of 331 BCF, and technical revisions of 204 BCF, partially offset by downward revisions due to increasing operating costs of 60 BCF.

In 2022, purchases in Africa were a result of the acquisition of additional interest in the Libya Waha Concession. In our equity affiliates, purchases were due to the acquisition of additional affiliate interest in Asia Pacific.

•Extensions and discoveries: In 2024, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Canada extensions and discoveries were in Montney. Extensions and discoveries in our equity affiliates were in the Middle East and Australia.

In 2023, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. Canada extensions and discoveries were in Montney. Extensions and discoveries in our equity affiliates were in Australia.

In 2022, extensions and discoveries in Lower 48 were primarily within unconventional plays in the Permian Basin. In Europe, extensions and discoveries were due to additional planned development. Extensions and discoveries in our equity affiliates were primarily in the Middle East.

•Sales: In 2023, Lower 48 sales represent the disposition of noncore assets.

In 2022, Lower 48 sales represent the disposition of noncore assets. Sales in our consolidated operations in Asia Pacific/Middle East represent the disposition of our Indonesia assets.


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Years Ended December 31	Bitumen
	Millions of Barrels
	Canada	Total*
Developed and Undeveloped

End of 2021	257	257
Revisions	(17)	(17)
Improved recovery	—	—
Purchases	—	—
Extensions and discoveries	—	—
Production	(24)	(24)
Sales	—	—
End of 2022	216	216
Revisions	15	15
Improved recovery	—	—
Purchases	209	209
Extensions and discoveries	—	—
Production	(30)	(30)
Sales	—	—
End of 2023	410	410
Revisions	118	118
Improved recovery	—	—
Purchases	—	—
Extensions and discoveries	—	—
Production	(45)	(45)
Sales	—	—
End of 2024	483	483


Years Ended December 31	Bitumen
	Millions of Barrels
	Canada	Total*
Developed

End of 2021	150	150
End of 2022	127	127
End of 2023	293	293
End of 2024	230	230







Undeveloped

End of 2021	107	107
End of 2022	89	89
End of 2023	117	117
End of 2024	253	253

*There are no Bitumen reserves associated with our Equity Affiliates.

Notable changes in proved bitumen reserves in the three years ended December 31, 2024, included:

•Revisions: In 2024, upward revisions of 125 million barrels due to changes in development timing was partially offset by downward revisions due to price of 7 million barrels.

In 2023, the upward revision of 15 million barrels is primarily due to the impact of price on variable royalties.

In 2022, the impact of variable royalties on price resulted in downward revisions of 30 million barrels, partially offset by upward revisions primarily due to changes in development timing for specific pad locations from the Surmont development program.

•Purchases: In 2023, purchases in Canada were a result of the acquisition of the remaining 50 percent working interest in Surmont.


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Years Ended December 31	Total Proved Reserves
	Millions of Barrels of Oil Equivalent
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed and Undeveloped

End of 2021	1,555	2,775	4,330	290	299	249	220	5,388	713	6,101
Revisions	(35)	292	257	(15)	52	19	(5)	308	149	457
Improved recovery	—	—	—	—	—	3	—	3	—	3
Purchases	—	13	13	—	—	—	50	63	80	143
Extensions and discoveries	15	414	429	1	26	—	—	456	241	697
Production	(85)	(364)	(449)	(31)	(46)	(31)	(15)	(572)	(81)	(653)
Sales	—	(82)	(82)	—	—	(67)	—	(149)	—	(149)
End of 2022	1,450	3,048	4,498	245	331	173	250	5,497	1,102	6,599
Revisions	(98)	332	234	20	12	9	1	276	(14)	262
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	—	4	4	209	—	—	—	213	—	213
Extensions and discoveries	219	94	313	45	3	20	—	381	10	391
Production	(83)	(387)	(470)	(38)	(43)	(26)	(19)	(596)	(82)	(678)
Sales	—	(29)	(29)	—	—	—	—	(29)	—	(29)
End of 2023	1,488	3,062	4,550	481	303	176	232	5,742	1,016	6,758
Revisions	25	367	392	127	3	16	52	590	(6)	584
Improved recovery	—	—	—	—	—	—	—	—	—	—
Purchases	32	768	800	—	—	—	91	891	—	891
Extensions and discoveries	14	59	73	23	—	—	—	96	220	316
Production	(81)	(413)	(494)	(60)	(48)	(26)	(21)	(649)	(83)	(732)
Sales	—	(5)	(5)	—	—	—	—	(5)	—	(5)
End of 2024	1,478	3,838	5,316	571	258	166	354	6,665	1,147	7,812


Years Ended December 31	Total Proved Reserves
	Millions of Barrels of Oil Equivalent
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
Developed

End of 2021	1,424	1,767	3,191	166	244	212	207	4,020	631	4,651
End of 2022	1,357	1,676	3,033	147	240	155	231	3,806	751	4,557
End of 2023	1,222	1,639	2,861	320	216	142	210	3,749	675	4,424
End of 2024	1,202	2,387	3,589	272	215	136	297	4,509	606	5,115







Undeveloped

End of 2021	131	1,008	1,139	124	55	37	13	1,368	82	1,450
End of 2022	93	1,372	1,465	98	91	18	19	1,691	351	2,042
End of 2023	266	1,423	1,689	161	87	34	22	1,993	341	2,334
End of 2024	276	1,451	1,727	299	43	30	57	2,156	541	2,697

*All Equity Affiliate reserves are located in our Asia Pacific/Middle East Region.

Natural gas reserves are converted to BOE based on a 6:1 ratio: six MCF of natural gas converts to one BOE.


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Proved Undeveloped Reserves

The following table shows changes in total proved undeveloped reserves for 2024:


			Proved Undeveloped Reserves
			Millions of Barrels of Oil Equivalent
End of 2023			2,334
Revisions			535
Improved recovery			—
Purchases			57
Extensions and discoveries			281
Sales			(1)
Transfers to Proved Developed			(509)
End of 2024			2,697

Revisions of 535 MMBOE were predominately driven by progression of development plans in the Lower 48 unconventional plays, Canada Oil Sands and Libya, partially offset by 31MMBOE due to product price changes across the portfolio.

Purchases of 57 were primarily due to our acquisition of Marathon Oil in Lower 48 and Equatorial Guinea.

Extensions and discoveries were largely driven by the continued development planned in equity affiliates in Asia Pacific/Middle East. The remaining extensions and discoveries were driven by the continued development planned in the other geographic regions, including Canada, Lower 48 unconventional plays, and Alaska.

Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 75 percent of the transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development across the other geographic regions.

At both December 31, 2024 and 2023, our PUDs represented 35 percent of total proved reserves. Costs incurred for the year ended December 31, 2024, relating to the development of PUDs were $9.4 billion. A portion of our costs incurred each year relates to development projects where the PUDs will be converted to proved developed reserves in future years.

At the end of 2024, approximately 88 percent of total PUDs were under development or scheduled for development within five years of initial disclosure, including all of our Lower 48 PUDs. The PUDs to be developed beyond five years are in the Willow project in Alaska, a development that is currently underway with production anticipated in 2029 due to its large scale and remote location, as well as in major development areas which are currently producing and located in Canada and in our equity affiliate in Australia.


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Results of Operations

The company’s results of operations from oil and gas activities for the years 2024, 2023 and 2022 are shown in the following tables. Non-oil and gas activities, such as pipeline and marine operations, LNG operations, crude oil and gas marketing activities, and the profit element of transportation operations in which we have an ownership interest are excluded. Additional information about selected line items within the results of operations tables is shown below:

•Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are not consolidated.

•Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are consolidated.

•Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.

•Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the production of petroleum liquids and natural gas.

•Taxes other than income taxes include production, property and other non-income taxes.

•Depreciation of support equipment is reclassified as applicable.

•Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other miscellaneous expenses.

Results of Operations


Year Ended December 31, 2024	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total Consolidated Operations	Equity Affiliates*
Consolidated operations
Sales	$	5,574	19,028	24,602	2,567	3,469	1,847	1,488	—	33,973	917
Transfers	6		—	6	—	—	—	—	—	6	3,343
Transportation costs	(709)		—	(709)	—	—	—	—	—	(709)	—
Other revenues	—		108	108	(34)	(69)	3	117	13	138	18
Total revenues	4,871		19,136	24,007	2,533	3,400	1,850	1,605	13	33,408	4,278
Production costs excluding taxes	1,330		4,691	6,021	902	506	350	120	—	7,899	543
Taxes other than income taxes	410		1,372	1,782	31	36	108	4	—	1,961	1,181
Exploration expenses	74		85	159	80	68	40	8	1	356	—
Depreciation, depletion and amortization	1,175		6,422	7,597	594	689	424	67	—	9,371	484
Impairments	32		42	74	4	2	—	—	—	80	—
Other related expenses	(36)		49	13	(52)	(68)	—	5	14	(88)	(8)
Accretion	106		79	185	18	68	28	—	—	299	19
	1,780		6,396	8,176	956	2,099	900	1,401	(2)	13,530	2,059
Income tax provision (benefit)	461		1,407	1,868	224	1,539	222	1,306	(1)	5,158	623
Results of operations	$	1,319	4,989	6,308	732	560	678	95	(1)	8,372	1,436
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.


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Year Ended December 31,2023	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total Consolidated Operations	Equity Affiliates*
Consolidated operations
Sales	$	5,918	18,976	24,894	1,517	3,449	1,914	1,447	—	33,221	822
Transfers	5		—	5	—	—	—	—	—	5	3,429
Transportation costs	(611)		—	(611)	—	—	—	—	—	(611)	—
Other revenues	(4)		142	138	(1)	3	(1)	181	3	323	14
Total revenues	5,308		19,118	24,426	1,516	3,452	1,913	1,628	3	32,938	4,265
Production costs excluding taxes	1,242		4,175	5,417	602	499	348	74	1	6,941	493
Taxes other than income taxes	442		1,347	1,789	26	35	115	3	—	1,968	1,208
Exploration expenses	72		153	225	49	73	44	4	3	398	—
Depreciation, depletion and amortization	938		5,702	6,640	374	532	454	50	—	8,050	390
Impairments	—		7	7	6	—	—	—	—	13	—
Other related expenses	71		42	113	60	(24)	17	3	12	181	(8)
Accretion	94		65	159	12	61	27	—	—	259	30
	2,449		7,627	10,076	387	2,276	908	1,494	(13)	15,128	2,152
Income tax provision (benefit)	640		1,667	2,307	5	1,704	66	1,375	—	5,457	658
Results of operations	$	1,809	5,960	7,769	382	572	842	119	(13)	9,671	1,494
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.


Year Ended December 31,2022	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total Consolidated Operations	Equity Affiliates*
Consolidated operations
Sales	$	7,210	24,309	31,519	1,622	6,594	2,602	1,339	—	43,676	1,000
Transfers	6		—	6	—	—	—	—	—	6	4,272
Transportation costs	(647)		—	(647)	—	—	—	—	—	(647)	—
Other revenues	(1)		115	114	338	1	536	184	10	1,183	41
Total revenues	6,568		24,424	30,992	1,960	6,595	3,138	1,523	10	44,218	5,313
Production costs excluding taxes	1,160		3,600	4,760	581	511	342	55	—	6,249	491
Taxes other than income taxes	1,265		1,687	2,952	21	36	243	2	—	3,254	1,536
Exploration expenses	34		189	223	149	122	49	19	2	564	—
Depreciation, depletion and amortization	833		4,843	5,676	354	693	517	36	—	7,276	530
Impairments	2		(11)	(9)	(2)	(1)	—	—	—	(12)	—
Other related expenses	(19)		4	(15)	(41)	(178)	40	5	6	(183)	(2)
Accretion	78		55	133	11	62	25	—	—	231	27
	3,215		14,057	17,272	887	5,350	1,922	1,406	2	26,839	2,731
Income tax provision (benefit)	866		3,113	3,979	198	4,057	512	1,301	53	10,100	836
Results of operations	$	2,349	10,944	13,293	689	1,293	1,410	105	(51)	16,739	1,895
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.


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Statistics


Net Production	2024	2023	2022
	Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska	173	173	177
Lower 48	602	569	534
United States	775	742	711
Canada	17	9	6
Europe	69	64	71
Asia Pacific	59	60	61
Africa	49	48	36
Total consolidated operations	969	923	885
Equity affiliates—Asia Pacific/Middle East	13	13	13
Total company	982	936	898
Delaware Basin Area (Lower 48)*	301	274	258

Natural Gas Liquids
Consolidated operations
Alaska	15	16	17
Lower 48	279	256	221
United States	294	272	238
Canada	6	3	3
Europe	4	4	3
Total consolidated operations	304	279	244
Equity affiliates—Asia Pacific/Middle East	8	8	8
Total company	312	287	252
Delaware Basin Area (Lower 48)*	144	135	114

Bitumen
Consolidated operations—Canada	122	81	66
Total company	122	81	66

Natural Gas	Millions of Cubic Feet Daily
Consolidated operations
Alaska	39	38	34
Lower 48	1,625	1,457	1,402
United States	1,664	1,495	1,436
Canada	115	65	61
Europe	329	279	306
Asia Pacific	50	48	114
Africa	42	29	22
Total consolidated operations	2,200	1,916	1,939
Equity affiliates—Asia Pacific/Middle East	1,233	1,219	1,191
Total company	3,433	3,135	3,130
Delaware Basin Area (Lower 48)*	884	768	752

*At year-end 2024, 2023 and 2022, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves.


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Average Sales Prices	2024		2023	2022

Crude Oil Per Barrel
Consolidated operations
Alaska*	$	71.32	74.46	92.58
Lower 48	74.17		76.19	94.46
United States	73.49		75.75	93.96
Canada	64.47		66.19	79.94
Europe	81.09		84.56	99.88
Asia Pacific	82.42		84.79	105.52
Africa	80.65		83.07	97.85
Total international	79.97		83.33	100.75
Total consolidated operations	74.76		77.19	95.27
Equity affiliates—Asia Pacific/Middle East	76.76		78.45	97.31
Total operations	74.78		77.21	95.30

Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48	$	22.02	21.73	35.36
United States	22.02		21.73	35.36
Canada	29.59		26.13	37.70
Europe	45.50		41.13	54.52
Total international	33.60		34.56	46.16
Total consolidated operations	22.43		22.12	35.67
Equity affiliates—Asia Pacific/Middle East	51.53		47.09	61.22
Total operations	23.19		22.82	36.50

Bitumen Per Barrel
Consolidated operations—Canada	$	47.92	42.15	55.56

Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska	$	3.90	4.47	3.64
Lower 48	0.87		2.12	5.92
United States	0.88		2.13	5.92
Canada**	0.54		1.80	3.62
Europe	11.11		13.33	35.33
Asia Pacific	3.74		3.95	5.84
Africa	7.32		6.49	6.59
Total international	7.87		10.01	23.54
Total consolidated operations	2.61		3.89	10.56
Equity affiliates—Asia Pacific/Middle East	8.22		8.46	9.39
Total operations	4.69		5.69	10.60

*Average sales prices for Alaska crude oil above reflects a reduction for transportation costs in which we have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations.

**Average sales prices include unutilized transportation costs.


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	2024		2023	2022
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska	$	18.73	17.45	15.89
Lower 48	11.13		10.72	9.97
United States	12.22		11.76	10.97
Canada	15.03		15.86	18.73
Europe	10.80		11.89	11.20
Asia Pacific	14.27		14.02	11.71
Africa	5.85		3.83	3.77
Total international	12.36		12.28	12.36
Total consolidated operations	12.26		11.87	11.27
Equity affiliates—Asia Pacific/Middle East	6.56		6.03	6.14

Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada	$	15.19	14.42	17.62

Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska	$	5.77	6.21	17.33
Lower 48	3.25		3.46	4.67
United States	3.62		3.88	6.80
Canada	0.52		0.68	0.68
Europe	0.77		0.83	0.79
Asia Pacific	4.40		4.63	8.32
Africa	0.20		0.16	0.14
Total international	1.18		1.44	2.51
Total consolidated operations	3.04		3.37	5.87
Equity affiliates—Asia Pacific/Middle East	14.28		14.77	19.22

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska	$	16.55	13.18	11.41
Lower 48	15.23		14.64	13.42
United States	15.42		14.42	13.08
Canada	9.90		9.85	11.41
Europe	14.71		12.67	15.19
Asia Pacific	17.29		18.29	17.71
Africa	3.27		2.58	2.47
Total international	11.68		11.36	13.28
Total consolidated operations	14.54		13.77	13.12
Equity affiliates—Asia Pacific/Middle East	5.85		4.77	6.63

*Includes bitumen.


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Development and Exploration Activities

The following two tables summarize our net interest in productive and dry exploratory and development wells in the years ended December 31, 2024, 2023 and 2022. A “development well” is a well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field. Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well density or production history have not achieved statistical certainty of results. Excluded from the exploratory well count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada and CBM test wells located in Asia Pacific/Middle East.


Net Wells Completed
	Productive			Dry
	2024	2023	2022	2024	2023	2022
Exploratory
Consolidated operations
Alaska	—	—	—	—	2	—
Lower 48	39	38	118	—	2	—
United States	39	38	118	—	4	—
Canada	7	6	6	—	—	—
Europe	—	—	—	*	*	2
Asia Pacific/Middle East	*	—	—	—	—	1
Africa	—	—	—	1	—	3
Other areas	—	—	—	—	—	—
Total consolidated operations	46	44	124	1	4	6
Equity affiliates
Asia Pacific/Middle East	2	3	*	—	*	—
Total equity affiliates	2	3	*	—	*	—

Development
Consolidated operations
Alaska	13	11	11	—	—	—
Lower 48	507	494	388	—	—	—
United States	520	505	399	—	—	—
Canada	38	21	11	—	—	—
Europe	8	4	3	—	—	—
Asia Pacific/Middle East	23	20	22	—	—	—
Africa	5	4	2	—	—	—
Other areas	—	—	—	—	—	—
Total consolidated operations	594	554	437	—	—	—
Equity affiliates
Asia Pacific/Middle East	54	45	28	—	—	—
Total equity affiliates	54	45	28	—	—	—

*Our total proportionate interest was less than one.


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The table below represents the status of our wells drilling at December 31, 2024, and includes wells in the process of drilling or in active completion. It also represents gross and net productive wells, including producing wells and wells capable of production at December 31, 2024.

Wells at December 31, 2024


			Productive
	In Progress		Oil		Gas
	Gross	Net	Gross	Net	Gross	Net
Consolidated operations
Alaska	3	3	1,557	936	—	—
Lower 48	832	450	21,323	10,179	4,638	2,782
United States	835	453	22,880	11,115	4,638	2,782
Canada	62	62	213	213	174	174
Europe	14	2	497	84	65	4
Asia Pacific/Middle East	7	3	491	233	6	2
Africa	27	6	917	187	27	13
Other areas	—	—	—	—	—	—
Total consolidated operations	945	526	24,998	11,832	4,910	2,975
Equity affiliates
Asia Pacific/Middle East	422	65	—	—	5,461	1,615
Total equity affiliates	422	65	—	—	5,461	1,615

Acreage at December 31, 2024



	Thousands of Acres
	Developed		Undeveloped
	Gross	Net	Gross	Net
Consolidated operations
Alaska	741	566	1,038	1,012
Lower 48	4,773	3,318	10,258	8,100
United States	5,514	3,884	11,296	9,112
Canada	309	286	3,396	2,006
Europe	451	60	610	188
Asia Pacific/Middle East	422	152	10,341	7,630
Africa	440	140	12,545	2,561
Other areas	—	—	156	125
Total consolidated operations	7,136	4,522	38,344	21,622
Equity affiliates
Asia Pacific/Middle East	1,085	325	4,173	1,078
Total equity affiliates	1,085	325	4,173	1,078


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Supplementary Data			Table of Contents

Costs Incurred


Year Ended December 31	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total Consolidated Operations	Equity Affiliates*
2024
Consolidated operations
Unproved property acquisition	$	—	10,985	10,985	—	—	—	—	—	10,985	—
Proved property acquisition	297		12,118	12,415	(46)	—	—	1,100	—	13,469	—
	297		23,103	23,400	(46)	—	—	1,100	—	24,454	—
Exploration	98		548	646	239	49	46	7	1	988	18
Development	2,808		6,301	9,109	390	598	354	91	—	10,542	323
	$	3,203	29,952	33,155	583	647	400	1,198	1	35,984	341









2023
Consolidated operations
Unproved property acquisition	$	—	157	157	156	—	—	—	—	313	—
Proved property acquisition	—		106	106	2,973	—	—	—	—	3,079	—
	—		263	263	3,129	—	—	—	—	3,392	—
Exploration	67		396	463	144	45	49	4	3	708	46
Development	1,884		6,266	8,150	367	843	383	38	—	9,781	416
	$	1,951	6,925	8,876	3,640	888	432	42	3	13,881	462









2022
Consolidated operations
Unproved property acquisition	$	—	255	255	—	—	—	—	—	255	—
Proved property acquisition	—		249	249	—	—	—	104	—	353	881
	—		504	504	—	—	—	104	—	608	881
Exploration	61		1,278	1,339	99	121	59	3	2	1,623	25
Development	1,316		4,559	5,875	475	711	425	4	—	7,490	244
	$	1,377	6,341	7,718	574	832	484	111	2	9,721	1,150
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.

Capitalized Costs


At December 31	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total Consolidated Operations	Equity Affiliates*
2024
Consolidated operations
Proved property	$	29,435	88,461	117,896	10,904	12,986	11,274	2,304	—	155,364	11,691
Unproved property	107		13,883	13,990	1,256	41	96	97	10	15,490	2,133
	29,542		102,344	131,886	12,160	13,027	11,370	2,401	10	170,854	13,824
Accumulated depreciation, depletion and amortization	13,946		42,089	56,035	3,651	9,412	8,842	575	10	78,525	9,246
	$	15,596	60,255	75,851	8,509	3,615	2,528	1,826	—	92,329	4,578








2023
Consolidated operations
Proved property	$	26,358	70,621	96,979	11,255	14,124	10,923	1,113	—	134,394	11,159
Unproved property	108		3,393	3,501	1,443	65	90	98	9	5,206	2,263
	26,466		74,014	100,480	12,698	14,189	11,013	1,211	9	139,600	13,422
Accumulated depreciation, depletion and amortization	12,789		36,829	49,618	3,377	9,978	8,423	508	9	71,913	8,779
	$	13,677	37,185	50,862	9,321	4,211	2,590	703	—	67,687	4,643







*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region.


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Supplementary Data			Table of Contents

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs, including dismantlement, and future production costs, including taxes other than income taxes.

While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.

Discounted Future Net Cash Flows


	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
2024

Future cash inflows	$	79,396	164,264	243,660	24,685	18,148	10,405	26,592	323,490	51,975	375,465
Less:
Future production costs	39,861		73,663	113,524	9,433	5,924	4,189	2,678	135,748	29,807	165,555
Future development costs	12,766		21,143	33,909	2,370	3,611	1,586	693	42,169	3,234	45,403
Future income tax provisions	5,664		13,098	18,762	1,886	6,680	1,131	20,750	49,209	5,630	54,839
Future net cash flows	21,105		56,360	77,465	10,996	1,933	3,499	2,471	96,364	13,304	109,668
10 percent annual discount	9,742		17,667	27,409	4,217	94	1,087	828	33,635	5,170	38,805
Discounted future net cash flows	$	11,363	38,693	50,056	6,779	1,839	2,412	1,643	62,729	8,134	70,863
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $10,546.


	Millions of Dollars
	Alaska		Lower 48**	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total**
2023

Future cash inflows	$	83,793	141,307	225,100	19,937	23,569	11,322	21,562	301,490	51,887	353,377
Less:
Future production costs	39,069		57,303	96,372	8,699	6,576	4,586	1,008	117,241	28,579	145,820
Future development costs	13,685		21,391	35,076	2,058	3,802	1,458	400	42,794	2,299	45,093
Future income tax provisions	7,386		12,451	19,837	880	10,140	1,316	18,687	50,860	5,647	56,507
Future net cash flows	23,653		50,162	73,815	8,300	3,051	3,962	1,467	90,595	15,362	105,957
10 percent annual discount	11,522		16,850	28,372	2,723	432	1,257	570	33,354	5,543	38,897
Discounted future net cash flows	$	12,131	33,312	45,443	5,577	2,619	2,705	897	57,241	9,819	67,060
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $12,524.
**Certain amounts in Lower 48 have been revised to reflect additional Future cash inflows and Future production costs.


	Millions of Dollars
	Alaska		Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total Consolidated Operations	Equity Affiliates*	Total
2022

Future cash inflows	$	94,332	195,605	289,937	13,768	44,942	13,458	27,067	389,172	87,644	476,816
Less:
Future production costs	47,979		63,987	111,966	5,722	7,559	5,582	1,085	131,914	51,912	183,826
Future development costs	8,501		21,379	29,880	960	4,378	1,159	531	36,908	2,685	39,593
Future income tax provisions	8,882		23,136	32,018	863	25,416	1,780	23,615	83,692	8,988	92,680
Future net cash flows	28,970		87,103	116,073	6,223	7,589	4,937	1,836	136,658	24,059	160,717
10 percent annual discount	13,733		31,191	44,924	1,936	1,827	1,505	746	50,938	10,787	61,725
Discounted future net cash flows	$	15,237	55,912	71,149	4,287	5,762	3,432	1,090	85,720	13,272	98,992
*All Equity Affiliate activity is located in our Asia Pacific/Middle East Region. Total Discounted future net cash flows for Asia Pacific/Middle East was $16,704.


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Supplementary Data			Table of Contents

Sources of Change in Discounted Future Net Cash Flows


	Millions of Dollars
	Consolidated Operations					Equity Affiliates				Total Company
	2024		2023*		2022	2024		2023	2022	2024		2023*	2022
Discounted future net cash flows at the beginning of the year	$	57,241	$	85,720	52,695	$	9,819	13,272	5,000	$	67,060	98,992	57,695
Changes during the year
Revenues less production costs for the year	(23,410)		(23,706)		(33,532)	(2,536)		(2,550)	(3,245)	(25,946)		(26,256)	(36,777)
Net change in prices, and production costs	(10,025)		(51,887)		61,902	(941)		(4,519)	8,184	(10,966)		(56,406)	70,086
Extensions, discoveries and improved recovery, less estimated future costs	(1,015)		1,751		7,882	507		118	1,472	(508)		1,869	9,354
Development costs for the year	10,197		9,129		6,687	402		326	272	10,599		9,455	6,959
Changes in estimated future development costs	(3,512)		(6,754)		(4,088)	(274)		(150)	189	(3,786)		(6,904)	(3,899)
Purchases of reserves in place, less estimated future costs	11,068		3,024		3,353	—		—	1,282	11,068		3,024	4,635
Sales of reserves in place, less estimated future costs	(113)		(446)		(3,847)	—		—	—	(113)		(446)	(3,847)
Revisions of previous quantity estimates	14,175		9,047		13,080	23		492	2,193	14,198		9,539	15,273
Accretion of discount	8,137		12,414		7,021	1,199		1,635	616	9,336		14,049	7,637
Net change in income taxes	(14)		18,949		(25,433)	(65)		1,195	(2,691)	(79)		20,144	(28,124)
Total changes	5,488		(28,479)		33,025	(1,685)		(3,453)	8,272	3,803		(31,932)	41,297
Discounted future net cash flows at year end	$	62,729	$	57,241	85,720	$	8,134	9,819	13,272	$	70,863	67,060	98,992
*Certain amounts in Consolidated Operations have been revised to reflect adjustments to the discounted future net cash flows.

•The net change in prices and production costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price and production cost, discounted at 10 percent.

•Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

•Revisions of previous quantity estimates are calculated using production forecast changes for the year, including changes in the timing of production, multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

•The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production and development costs.

•The net change in income taxes is the annual change in the discounted future income tax provisions.


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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2024, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of December 31, 2024.

In the third quarter of 2023, we began a multi-year implementation of an updated global enterprise resource planning system (ERP). As a result, we have made corresponding changes to our business processes and information systems, updating applicable internal controls over financial reporting where necessary. As the phased implementation of the ERP system progresses, we expect to continue to modify or change certain processes and procedures which may result in further changes to our internal controls over financial reporting.

There have been no other changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

This report is included in Item 8 on page 71 and is incorporated herein by reference.

Report of Independent Registered Public Accounting Firm

This report is included in Item 8 on page 72 and is incorporated herein by reference.

Item 9B. Other Information

Insider Trading Arrangements

During the three-month period ended December 31, 2024, no officer or director of the company or any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.


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			Table of Contents

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding our executive officers appears in Part I of this report on page 30.

Code of Business Ethics and Conduct for Directors and Employees

We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our internet website at www.conocophillips.com (within the Investors>Corporate Governance section). Any waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our internet website.

We have adopted insider trading policies and procedures governing the purchase, sale and/or other dispositions of our securities by directors, officers and other personnel employed by us or any of our subsidiaries. All personnel are responsible for ensuring their “Related Parties” (as defined in the policies) comply as well. We have an additional insider trading policy that applies only to our directors, Section 16 officers and other designated officers and employees. We believe our insider trading policies are reasonably designed to promote compliance with insider trading laws, rules and regulations, the listing standards of the NYSE and Section 16 reporting requirements, as applicable.

All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2025 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2025, and is incorporated herein by reference.*

Item 11. Executive Compensation

Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2025 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2025, and is incorporated herein by reference.*

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2025 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2025, and is incorporated herein by reference.*

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2025 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2025, and is incorporated herein by reference.*

Item 14. Principal Accounting Fees and Services

Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2025 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2025, and is incorporated herein by reference.*

_________________________

* Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2025 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.


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Part IV

Item 15. Exhibits, Financial Statement Schedules

(a)1. Financial Statements and Supplementary Data

The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 70, are filed as part of this annual report.

2. Financial Statement Schedules

All financial statement schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.

3. Exhibits

The exhibits listed in the Index to Exhibits, which appears on pages 161 through 164, are filed as part of this annual report.


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ConocoPhillips

Index to Exhibits


		Incorporated by Reference
Exhibit No.	Description	Exhibit	Form	File No.
2.1	Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26, 2012.	2.1	8-K	001-32395

2.2†‡	Purchase and Sale Agreement, dated March 29, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.	2.1	10-Q	001-32395

2.3†‡	Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.	2.2	8-K	001-32395

2.4	Agreement and Plan of Merger, dated as of October 18, 2020, among ConocoPhillips, Falcon Merger Sub Corp. and Concho Resources Inc.	2.1	8-K	001-32395

2.5	Agreement and Plan of Merger, dated as of May 28, 2024, by and among ConocoPhillips, Puma Merger Sub Corp, and Marathon Oil Corporation .	2.1	8-K	001-32395

3.1	Amended and Restated Certificate of Incorporation.	3.1	10-Q	001-32395

3.2	Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips.	3.2	8-K	000-49987



3.3	Restated Certificate of Incorporation of ConocoPhillips Company, dated February 6, 2019.	3.4	10-K	001-32395

3.4	Second Amended and Restated Bylaws, dated May 16, 2023	3.1	10-Q	001-32395

	ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request.

4.1	Description of Securities of the Registrant.	4.1	10-K	001-32395

10.1	Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	10.1	8-K	001-32395

10.2	Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	10.2	8-K	001-32395

10.3	Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	10.3	8-K	001-32395

10.4	Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012.	10.4	8-K	001-32395

10.5.1	Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998.	10.17.3	10-K	001-32395

10.5.2	First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust Agreement, dated May 3, 1999.	10.17.4	10-K	001-32395

10.5.3	Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust Agreement, dated January 15, 2002.	10.17.5	10-K	001-32395


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10.5.4	Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust Agreement, dated October 5, 2006.	10.17.6	10-K	001-32395

10.5.5	Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust Agreement, dated May 1, 2012.	10.17.7	10-K	001-32395

10.5.6	Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust Agreement, dated May 20, 2015.	10.17.8	10-K	001-32395

10.6.1	Successor Trustee Agreement of the Deferred Compensation Trust Agreement for Non-Employee Directors of ConocoPhillips dated July 31, 2020.	10.1	10-Q	001-32395

10.6.2	First Amendment to the Successor Trust Agreement of the Deferred Compensation Trust Agreement for Non-Employee Directors of ConocoPhillips, dated August 4, 2020.	10.2	10-Q	001-32395

10.7	Omnibus Securities Plan of Phillips Petroleum Company.	10.19	10-K	004-49987

10.8	2002 Omnibus Securities Plan of Phillips Petroleum Company.	10.26	10-K	000-49987

10.9.1	2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	Schedule 14A	Proxy	000-49987

10.9.2	Form of Performance Share Unit Award Agreement under the Performance Share Program under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	10.27	10-K	001-32395

10.10	Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007.	10.30	10-K	001-32395

10.11	2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	Schedule 14A	Proxy	001-32395

10.12.1	2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	Schedule 14A	Proxy	001-32395

10.12.2	Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013.	10.26.6	10-K	001-32395

10.12.3	Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.	10.1	10-Q	001-32395

10.12.4	Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.	10.3	10-Q	001-32395

10.12.5	Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.	10.5	10-Q	001-32395

10.13.1	2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	10.1	8-K	001-32395

10.13.2	Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 16, 2016.	10.26.12	10-K	001-32395

10.13.3	Form of Performance Share Unit Award Terms and Conditions for Performance Period 18, as part of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2018.	10.26.24	10-K	001-32395


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10.13.4	Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.	10.1	10-Q	001-32395

10.13.5	Form of Executive Restricted Stock Unit Award Terms and Conditions, as part of the ConocoPhillips Executive Restricted Stock Unit Program, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 11, 2020.	10.1	10-Q	001-32395

10.14.1	2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips	10.1	8-K	001-32395

10.14.2	Form of Performance Share Unit Award Terms and Conditions for Performance Period 24, as part of the ConocoPhillips Performance Share Program granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2024.	10.1	10-Q	001-32395

10.14.3	Form of Executive Restricted Stock Unit Award Terms and Conditions, as part of the ConocoPhillips Executive Restricted Stock Unit Program, granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2024.	10.2	10-Q	001-32395

10.14.4	Form of 2024 Retention Award Terms and Conditions, granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	10.3	10-Q	001-32395

10.14.5	Form of 2024 Inducement Award Terms and Conditions, granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.	10.4	10-Q	001-32395

10.14.6*	Form of Performance Share Unit Award Terms and Conditions for Performance Period 25, as part of the ConocoPhillips Performance Share Program granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 11, 2025.

10.14.7*	Form of Executive Restricted Stock Unit Award Terms and Conditions, as part of the ConocoPhillips Executive Restricted Stock Unit Program, granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 11, 2025.

10.15	Amended and Restated ConocoPhillips Key Employee Supplemental Retirement Plan, dated January 1, 2020.	10.10.1	10-K	001-32395

10.16.1	Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title I, dated January 1, 2020.	10.11.1	10-K	001-32395

10.16.2	Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated January 1, 2024.	10.16.2	10-K	001-32395

10.17	Amended and Restated Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated January 1, 2024.	10.17	10-K	001-32395

10.18.1	Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title I, dated January 1, 2020.	10.19.1	10-K	001-32395

10.18.2	Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title II, dated January 1, 2024.	10.18.2	10-K	001-32395

10.19	Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan, effective December 2, 2021.	10.20.1	10-K	001-32395

10.20.1	Form of Non-Employee Director Restricted Stock Units Terms and Conditions, as part of the Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15, 2016.	10.3	10-Q	001-32395

10.20.2*	Form of Non-Employee Director Restricted Stock Units Terms and Conditions, granted under the 2023 Omnibus Stock and Performance Incentive Plan of ConocoPhillips and subject to the Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15, 2025.


163			ConocoPhillips 2024 10-K


			Table of Contents

10.21

Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips.

10.17

10-K

001-32395

10.22.1

ConocoPhillips Directors’ Charitable Gift Program.

10.40

10-K

000-49987

10.22.2

First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program.

10-Q

001-32395

10.23

Amended and Restated 409A Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips, dated January 1, 2020.

10.27

10-K

001-32395

10.24

Amendment and Restatement of ConocoPhillips Executive Severance Plan, dated December 2, 2021.

10.47

10-K

001-32395

10.25

Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits Plan, dated April 19, 2012.

10.9

10-Q

001-32395

10.26

Purchase and Sale Agreement, dated as of September 20, 2021, by and between Shell Enterprises LLC and ConocoPhillips.

10.1

10-Q

001-32395

10.27

Form of Aircraft Time Sharing Agreement by and between certain executives and ConocoPhillips dated June 21, 2021.

10.2

10-Q

001-32395

10.28

Letter agreement with Timothy A. Leach, dated April 28, 2022.

10.1

10-Q

001-32395

10.29

Form of Aircraft Time Sharing Agreement by and between certain executives and ConocoPhillips dated November 14, 2023.

10.29

10-K

001-32395

19*

Insider Trading Policies of ConocoPhillips

21*

List of Subsidiaries of ConocoPhillips.

22*

Subsidiary Guarantors of Guaranteed Securities.

23.1*

Consent of Ernst & Young LLP.

23.2*

Consent of DeGolyer and MacNaughton.

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32**

Certifications pursuant to 18 U.S.C. Section 1350.

ConocoPhillips Clawback Policy effective October 2, 2023.

97.2

10-K

001-32395

99*

Report of DeGolyer and MacNaughton.

101.INS*

Inline XBRL Instance Document.

101.SCH*

Inline XBRL Schema Document.

101.CAL*

Inline XBRL Calculation Linkbase Document.

101.DEF*

Inline XBRL Definition Linkbase Document.

101.LAB*

Inline XBRL Labels Linkbase Document.

101.PRE*

Inline XBRL Presentation Linkbase Document.

104*

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.

**Furnished herewith.

† The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ConocoPhillips agrees to furnish a copy of any schedule omitted from this exhibit to the SEC upon request.

‡ ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.


ConocoPhillips 2024 10-K			164


			Table of Contents

Signature

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			CONOCOPHILLIPS



February 18, 2025			/s/ Ryan M. Lance
			Ryan M. Lance Chairman of the Board of Directors and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 18, 2025, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.


Signature						Title


/s/ Ryan M. Lance						Chairman of the Board of Directors
Ryan M. Lance						and Chief Executive Officer
						(Principal executive officer)


/s/ William L. Bullock, Jr.						Executive Vice President and
William L. Bullock, Jr.						Chief Financial Officer
						(Principal financial officer)


/s/ Christopher P. Delk						Vice President, Controller
Christopher P. Delk						and General Tax Counsel
						(Principal accounting officer)


165			ConocoPhillips 2024 10-K


			Table of Contents


/s/ Dennis V. Arriola						Director
Dennis V. Arriola


/s/ Nelda J. Connors						Director
Nelda J. Connors


/s/ Gay Huey Evans						Director
Gay Huey Evans






/s/ Jeffrey A. Joerres						Director
Jeffrey A. Joerres


/s/ Timothy A. Leach						Director
Timothy A. Leach


/s/ William H. McRaven						Director
William H. McRaven


/s/ Sharmila Mulligan						Director
Sharmila Mulligan






/s/ Arjun N. Murti						Director
Arjun N. Murti


/s/ Robert A. Niblock						Director
Robert A. Niblock


/s/ David T. Seaton						Director
David T. Seaton


/s/ R.A. Walker						Director
R.A. Walker


ConocoPhillips 2024 10-K			166

CONOCOPHILLIPS - Annual Report: 2024 (Form 10-K)

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