Item 8. Financial Statements and Supplementary Data

ConocoPhillips

Index to Financial Statements
			Page
Reports of Management			69
Reports of Independent Registered Public Accounting Firm (PCAOB ID #42)			70
Consolidated Income Statement for the years ended December 31, 2022, 2021 and 2020			74
Consolidated Statement of Comprehensive Income for the years ended December 31, 2022, 2021 and 2020			75
Consolidated Balance Sheet at December 31, 2022 and 2021			76
Consolidated Statement of Cash Flows for the years ended December 31, 2022, 2021 and 2020			77
Consolidated Statement of Changes in Equity for the years ended December 31, 2022, 2021 and 2020			78
Notes to Consolidated Financial Statements			79
Supplementary Information
Oil and Gas Operations			134

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			Table of Contents

Reports of Management

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

Assessment of Internal Control Over Financial Reporting

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

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

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2022.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2022, and their report is included herein.

/s/ Ryan M. Lance			/s/ William L. Bullock, Jr.
Ryan M. Lance			William L. Bullock, Jr.
Chairman and Chief Executive Officer			Executive Vice President and Chief Financial Officer

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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 the Financial Statements

We have audited the accompanying consolidated balance sheets of ConocoPhillips (the Company) as of December 31, 2022 and 2021, 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, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 16, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

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

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

Critical Audit Matters

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

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			Accounting for asset retirement obligations for certain offshore properties
Description of the Matter			At December 31, 2022, asset retirement obligations (ARO) totaled $6.4 billion. As further described in Note 8, the Company records ARO in the period in which they are incurred, typically when the asset is installed at the production location. The estimation of obligations related to certain offshore assets requires significant judgment given the magnitude and higher estimation uncertainty related to plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms and facilities (collectively, removal costs). Furthermore, as certain of these assets are nearing the end of their operations, the impact of changes in these ARO may result in a material impact to earnings given the relatively short remaining useful lives of the assets. Auditing the Company’s ARO for the obligations identified above is complex and highly judgmental due to the significant estimation required by management in determining the obligations. In particular, the estimates were sensitive to significant subjective assumptions such as removal cost estimates and end of field life, which are affected by expectations about future market or economic conditions.
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 ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. We also tested management’s controls over the completeness and accuracy of the financial data used in the valuation. To test the ARO for the obligations identified above, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, including removal cost estimates and end of field life assumptions. For example, we evaluated removal cost estimates by comparing to settlements and recent removal activities and costs. We also compared end of field life assumptions to production forecasts.
			Depreciation, depletion and amortization of proved oil and gas properties, plants and equipment
Description of the Matter			At December 31, 2022, the net book value of the Company’s proved oil and gas properties, plants and equipment (PP&E) was $55 billion, and depreciation, depletion and amortization (DD&A) expense was $7.3 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 geological and engineering data when estimating proved oil and gas reserves. Estimating proved oil and gas reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating proved oil and gas reserves, management also used an independent petroleum engineering consulting firm to perform a review of the processes and controls used by the Company’s internal reservoir engineers to determine estimates of proved oil and gas reserves. Auditing the Company’s DD&A calculation is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineering consulting firm 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.

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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 the financial 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 and the independent petroleum engineering consulting firm used to review the Company’s processes and controls. In addition, in assessing whether we can use the work of the internal reservoir engineers, we evaluated the completeness and accuracy of the financial 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.

/s/ Ernst & Young LLP

We have served as ConocoPhillips’ auditor since 1949.

Houston, Texas

February 16, 2023

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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, 2022, 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, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, 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, 2022, and the related notes and our report dated February 16, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ Ernst & Young LLP

Houston, Texas

February 16, 2023

73			ConocoPhillips 2022 10-K

Financial Statements			Table of Contents

Consolidated Income Statement			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2022			2021			2020
Revenues and Other Income
Sales and other operating revenues			$	78,494		45,828			18,784
Equity in earnings of affiliates			2,081			832			432
Gain on dispositions			1,077			486			549
Other income (loss)			504			1,203			(509)
Total Revenues and Other Income			82,156			48,349			19,256
Costs and Expenses
Purchased commodities			33,971			18,158			8,078
Production and operating expenses			7,006			5,694			4,344
Selling, general and administrative expenses			623			719			430
Exploration expenses			564			344			1,457
Depreciation, depletion and amortization			7,504			7,208			5,521
Impairments			(12)			674			813
Taxes other than income taxes			3,364			1,634			754
Accretion on discounted liabilities			250			242			252
Interest and debt expense			805			884			806
Foreign currency transaction gains			(100)			(22)			(72)
Other expenses			(47)			102			13
Total Costs and Expenses			53,928			35,637			22,396
Income (loss) before income taxes			28,228			12,712			(3,140)
Income tax provision (benefit)			9,548			4,633			(485)
Net income (loss)			18,680			8,079			(2,655)
Less: net income attributable to noncontrolling interests			—			—			(46)
Net Income (Loss) Attributable to ConocoPhillips			$	18,680		8,079			(2,701)
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic			$	14.62		6.09			(2.51)
Diluted			14.57			6.07			(2.51)
Average Common Shares Outstanding (in thousands)
Basic			1,274,028			1,324,194			1,078,030
Diluted			1,278,163			1,328,151			1,078,030

See Notes to Consolidated Financial Statements.

ConocoPhillips 2022 10-K			74

Financial Statements			Table of Contents

Consolidated Statement of Comprehensive Income			ConocoPhillips

Years Ended December 31			Millions of Dollars
			2022			2021			2020
Net Income (Loss)			$	18,680		8,079			(2,655)
Other comprehensive income (loss)
Defined benefit plans
Prior service (cost) credit arising during the period			(10)			—			29
Reclassification adjustment for amortization of prior service credit included in net income (loss)			(39)			(38)			(32)
Net change			(49)			(38)			(3)
Net actuarial gain (loss) arising during the period			(623)			357			(210)
Reclassification adjustment for amortization of net actuarial losses included in net income (loss)			72			178			117
Net change			(551)			535			(93)
Nonsponsored plans*			5			5			1
Income taxes on defined benefit plans			178			(108)			20
Defined benefit plans, net of tax			(417)			394			(75)
Unrealized holding gain (loss) on securities			(13)			(2)			2
Reclassification adjustment for loss included in net income			(1)			(1)			—
Income taxes on unrealized holding loss on securities			3			1			—
Unrealized holding gain (loss) on securities, net of tax			(11)			(2)			2
Foreign currency translation adjustments			(623)			(124)			209
Income taxes on foreign currency translation adjustments			1			—			3
Foreign currency translation adjustments, net of tax			(622)			(124)			212
Other Comprehensive Income (Loss), Net of Tax			(1,050)			268			139
Comprehensive Income (Loss)			17,630			8,347			(2,516)
Less: comprehensive income attributable to noncontrolling interests			—			—			(46)
Comprehensive Income (Loss) Attributable to ConocoPhillips			$	17,630		8,347			(2,562)

***Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

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
			2022			2021
Assets
Cash and cash equivalents			$	6,458		5,028
Short-term investments			2,785			446
Accounts and notes receivable (net of allowance of $2 and $2, respectively)			7,075			6,543
Accounts and notes receivable—related parties			13			127
Investment in Cenovus Energy			—			1,117
Inventories			1,219			1,208
Prepaid expenses and other current assets			1,199			1,581
Total Current Assets			18,749			16,050
Investments and long-term receivables			8,225			7,113
Net properties, plants and equipment (net of accumulated DD&A of $66,630 and $64,735, respectively)			64,866			64,911
Other assets			1,989			2,587
Total Assets			$	93,829		90,661
Liabilities
Accounts payable			$	6,113		5,002
Accounts payable—related parties			50			23
Short-term debt			417			1,200
Accrued income and other taxes			3,193			2,862
Employee benefit obligations			728			755
Other accruals			2,346			2,179
Total Current Liabilities			12,847			12,021
Long-term debt			16,226			18,734
Asset retirement obligations and accrued environmental costs			6,401			5,754
Deferred income taxes			7,726			6,179
Employee benefit obligations			1,074			1,153
Other liabilities and deferred credits			1,552			1,414
Total Liabilities			45,826			45,255
Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value) Issued (2022—2,100,885,134 shares; 2021—2,091,562,747 shares)
Par value			21			21
Capital in excess of par			61,142			60,581
Treasury stock (at cost: 2022—877,029,062 shares; 2021—789,319,875 shares)			(60,189)			(50,920)
Accumulated other comprehensive loss			(6,000)			(4,950)
Retained earnings			53,029			40,674
Total Equity			48,003			45,406
Total Liabilities and Equity			$	93,829		90,661

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
			2022			2021			2020
Cash Flows From Operating Activities
Net income (loss)			$	18,680		8,079			(2,655)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization			7,504			7,208			5,521
Impairments			(12)			674			813
Dry hole costs and leasehold impairments			340			44			1,083
Accretion on discounted liabilities			250			242			252
Deferred taxes			2,086			1,346			(834)
Undistributed equity earnings			942			446			645
Gain on dispositions			(1,077)			(486)			(549)
(Gain) loss on investment in Cenovus Energy			(251)			(1,040)			855
Other			86			(788)			43
Working capital adjustments
Decrease (increase) in accounts and notes receivable			(963)			(2,500)			521
Increase in inventories			(38)			(160)			(25)
Decrease (increase) in prepaid expenses and other current assets			(173)			(649)			76
Increase (decrease) in accounts payable			901			1,399			(249)
Increase (decrease) in taxes and other accruals			39			3,181			(695)
Net Cash Provided by Operating Activities			28,314			16,996			4,802
Cash Flows From Investing Activities
Capital expenditures and investments			(10,159)			(5,324)			(4,715)
Working capital changes associated with investing activities			520			134			(155)
Acquisition of businesses, net of cash acquired			(60)			(8,290)			—
Proceeds from asset dispositions			3,471			1,653			1,317
Net sales (purchases) of investments			(2,629)			3,091			(658)
Collection of advances/loans—related parties			114			105			116
Other			2			87			(26)
Net Cash Used in Investing Activities			(8,741)			(8,544)			(4,121)
Cash Flows From Financing Activities
Issuance of debt			2,897			—			300
Repayment of debt			(6,267)			(505)			(254)
Issuance of company common stock			362			145			(5)
Repurchase of company common stock			(9,270)			(3,623)			(892)
Dividends paid			(5,726)			(2,359)			(1,831)
Other			(49)			7			(26)
Net Cash Used in Financing Activities			(18,053)			(6,335)			(2,708)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash			(224)			(34)			(20)
Net Change in Cash, Cash Equivalents and Restricted Cash			1,296			2,083			(2,047)
Cash, cash equivalents and restricted cash at beginning of period			5,398			3,315			5,362
Cash, Cash Equivalents and Restricted Cash at End of Period			$	6,694		5,398			3,315

Restricted cash of $236 million is included in the “Other assets” line of our Consolidated Balance Sheet as of December 31, 2022.

Restricted cash of $152 million and $218 million is included in the “Prepaid expenses and other current assets” and “Other assets” lines, respectively, of our Consolidated Balance Sheet as of December 31, 2021.

See Notes to Consolidated Financial Statements.

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Financial Statements			Table of Contents

Consolidated Statement of Changes in Equity			ConocoPhillips

			Millions of Dollars
			Attributable to ConocoPhillips
			Common Stock
			Par Value			Capital in Excess of Par			Treasury Stock			Accum. Other Comprehensive Income (Loss)			Retained Earnings			Non- Controlling Interests			Total
Balances at December 31, 2019			$	18		46,983			(46,405)			(5,357)			39,742			69			35,050
Net income (loss)															(2,701)			46			(2,655)
Other comprehensive income (loss)												139									139
Dividends declared—ordinary ($1.69 per share of common stock)															(1,831)						(1,831)
Repurchase of company common stock									(892)												(892)
Distributions to noncontrolling interests and other																		(32)			(32)
Disposition																		(84)			(84)
Distributed under benefit plans						150															150
Other															3			1			4
Balances at December 31, 2020			$	18		47,133			(47,297)			(5,218)			35,213			—			29,849
Net income (loss)															8,079						8,079
Other comprehensive income (loss)												268									268
Dividends declared
Ordinary ($1.75 per share of common stock)															(2,359)						(2,359)
Variable return of cash ($0.20 per share of common stock)															(260)						(260)
Acquisition of Concho			3			13,122															13,125
Repurchase of company common stock									(3,623)												(3,623)
Distributed under benefit plans						326															326
Other															1						1
Balances at December 31, 2021			$	21		60,581			(50,920)			(4,950)			40,674			—			45,406
Net income (loss)															18,680						18,680
Other comprehensive income (loss)												(1,050)									(1,050)
Dividends declared
Ordinary ($1.89 per share of common stock)															(2,419)						(2,419)
Variable return of cash ($3.10 per share of common stock)															(3,908)						(3,908)
Repurchase of company common stock									(9,270)												(9,270)
Distributed under benefit plans						561															561
Other									1						2						3
Balances at December 31, 2022			$	21		61,142			(60,189)			(6,000)			53,029			—			48,003

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Notes to Consolidated Financial Statements			Table of Contents

Notes to Consolidated Financial Statements

Note 1—Accounting Policies

• Consolidation Principles and Investments**—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and, if applicable, variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is measured at fair value except when the investment does not have a readily determinable fair value. For those exceptions, it will be measured at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost. We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. See Note 24.

• Foreign Currency Translation**—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive loss in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Some of our foreign operations use their local currency as the functional currency.

• Use of Estimates**—The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

• Revenue Recognition**—Revenues associated with the sales of crude oil, bitumen, natural gas, LNG, NGLs and other items are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership and whether the customer has accepted delivery and a right to payment exists. These products are typically sold at prevailing market prices. We allocate variable market-based consideration to deliveries (performance obligations) in the current period as that consideration relates specifically to our efforts to transfer control of current period deliveries to the customer and represents the amount we expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or less.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

• Shipping and Handling Costs**—We typically incur shipping and handling costs prior to control transferring to the customer and account for these activities as fulfillment costs. Accordingly, we include shipping and handling costs in production and operating expenses for production activities. Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs billed to customers are treated as a component of the transaction price and recorded as a component of revenue when the customer obtains control.

• Cash Equivalents**—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

• Short-Term Investments**—Short-term investments include investments in bank time deposits and marketable securities (commercial paper and government obligations) which are carried at cost plus accrued interest and have original maturities of greater than 90 days but within one year or when the remaining maturities are within one year. We also invest in financial instruments classified as available for sale debt securities which are carried at fair value. Those instruments are included in short-term investments when they have remaining maturities of one year or less, as of the balance sheet date.

• Long-Term Investments in Debt Securities**—Long-term investments in debt securities includes financial instruments classified as available for sale debt securities with remaining maturities greater than one year as of the balance sheet date. They are carried at fair value and presented within the “Investments and long-term receivables” line of our consolidated balance sheet.

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Notes to Consolidated Financial Statements			Table of Contents

• Inventories**—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. The majority of our commodity-related inventories are recorded at cost using the LIFO basis. We measure these inventories at the lower-of-cost-or-market in the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weighted-average-cost method and the FIFO method, consistent with industry practice.

• Fair Value Measurements**—Assets and liabilities measured at fair value and required to be categorized within the fair value hierarchy are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

• Derivative Instruments**—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. We do not apply hedge accounting to our derivative instruments.

• Oil and Gas Exploration and Development**—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption PP&E. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 6.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

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• Capitalized Interest**—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

• Depreciation and Amortization**—Depreciation and amortization of PP&E on producing hydrocarbon properties and SAGD facilities and certain pipeline and LNG assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

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

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.

Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

• Maintenance and Repairs**—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

• Property Dispositions**—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When partial units of depreciable property are disposed of or retired which do not significantly alter the DD&A rate, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

• Asset Retirement Obligations and Environmental Costs**—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. See Note 8.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired through a business combination, which we record on a discounted basis) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable and estimable.

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• Impairment of Investments in Nonconsolidated Entities**—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

• Guarantees**—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

• Share-Based Compensation**—We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

• Income Taxes**—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income and temporary differences related to the cumulative translation adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties related to unrecognized tax benefits are reflected in production and operating expenses.

• Taxes Collected from Customers and Remitted to Governmental Authorities**—Sales and value-added taxes are recorded net.

• Net Income (Loss) Per Share of Common Stock**—Basic net income (loss) per share (EPS) is calculated using the two-class method. Under the two-class method, all earnings (distributed and undistributed) are allocated to common stock (including fully vested stock and unit awards that have not yet been issued as common stock) and participating securities. ConocoPhillips grants RSUs under its share-based compensation programs, the majority of which entitle recipients to receive non-forfeitable dividends during the vesting period on a basis equivalent to dividends paid to holders of the Company’s common stock. See Note 16. These unvested RSUs meet the definition of participating securities based on their respective rights to receive non-forfeitable dividends and are treated as a separate class of securities in computing basic EPS. Participating securities are not included as incremental shares in computing diluted EPS. Diluted EPS includes the potential impact of contingently issuable shares, including awards which require future service as a condition of delivery of the underlying common stock. Diluted EPS is calculated under both the two-class and treasury stock methods, and the more dilutive amount is reported. Diluted net loss per share does not assume conversion or exercise of securities as that would always have an antidilutive effect. Treasury stock is excluded from the daily weighted-average number of common shares outstanding in both calculations. See Note 23.

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Note 2—Inventories

Inventories at December 31 were:

			Millions of Dollars
			2022			2021
Crude oil and natural gas			$	641		647
Materials and supplies			578			561
Total inventories			$	1,219		1,208
Inventories valued on the LIFO basis			$	396		395

The estimated excess of current replacement cost over LIFO cost of inventories was approximately $149 million and $251 million at December 31, 2022 and 2021, respectively.

Note 3—Acquisitions and Dispositions

All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on dispositions” line on our consolidated income statement. All cash proceeds and payments are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows.

2022

Acquisition of Additional Shareholding Interest in Australia Pacific LNG Pty Ltd (APLNG)

In February 2022, we completed the acquisition of an additional 10 percent interest in APLNG from Origin Energy for approximately $1.4 billion, after customary adjustments, in an all-cash transaction resulting from the exercise of our preemption right. This increased our ownership in APLNG to 47.5 percent, with Origin Energy and Sinopec owning

27.5 percent and 25.0 percent, respectively. APLNG is reported as an equity investment in our Asia Pacific segment.

Qatar Liquefied Gas Company Limited (8) (QG8)

During 2022, we were awarded a 25 percent interest in a new joint venture (QG8) with QatarEnergy that will participate in the North Field East (NFE) LNG project. QG8 has a 12.5 percent interest in the NFE project and is reported as an equity method investment in our Europe, Middle East and North Africa segment. See Note 4.

Asset Acquisition

In September 2022, we completed the acquisition of an additional working interest in certain Eagle Ford acreage in the Lower 48 segment for cash consideration of $236 million after customary adjustments. This agreement was accounted for as an asset acquisition, with the consideration allocated primarily to PP&E.

Assets Sold

During 2022, we sold our interests in certain noncore assets in our Lower 48 segment for net proceeds of $680 million, with no gain or loss recognized on sale. At the time of disposition, our interest in these assets had a net carrying value of $680 million, consisting of $825 million of assets, primarily related to $818 million of PP&E, and $145 million of liabilities, primarily related to AROs.

In March 2022, we completed the divestiture of our subsidiaries that held our Indonesia assets and operations, and based on an effective date of January 1, 2021, we received net proceeds of $731 million after customary adjustments and recognized a $534 million before-tax and $462 million after-tax gain related to this transaction. Together, the subsidiaries sold indirectly held our 54 percent interest in the Indonesia Corridor Block Production Sharing Contract (PSC) and 35 percent shareholding in the Transasia Pipeline Company. At the time of the disposition, the net carrying value was approximately $0.2 billion, excluding $0.2 billion of cash and restricted cash. The net book value consisted primarily of $0.3 billion of PP&E and $0.1 billion of ARO. The before-tax earnings associated with the subsidiaries sold, excluding the gain on disposition noted above, were $138 million and $604 million and $394 million for the years ended December 31, 2022, 2021 and 2020, respectively. Results of operations for the Indonesia interests sold were reported in our Asia Pacific segment.

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In 2022, we recorded contingent payments of $451 million relating to the previous dispositions of our interest in the Foster Creek Christina Lake Partnership and western Canada gas assets and our San Juan assets. The contingent payments are recorded as gain on disposition on our consolidated income statement and are reflected within our Canada and Lower 48 segments. In our Canada segment, the contingent payment, calculated and paid on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52 CAD per barrel. In our Lower 48 segment, the contingent payment, paid on an annual basis, is calculated monthly at $7 million per month in which the U.S. Henry Hub price is at or above $3.20 per MMBTU. The term of contingent payments in our Canada segment ended in the second quarter of 2022 and continues through 2023 for the Lower 48 segment. We recorded contingent payments of $369 million in 2021. No payments were recorded in 2020.

2021

During the year, we completed the acquisitions of Concho Resources Inc. (Concho) and of Shell Enterprises LLC’s (Shell) Permian assets. The acquisitions were accounted for as business combinations 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.

Acquisition of Concho Resources Inc.

In January 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production company with operations across New Mexico and West Texas focused in the Permian-based Delaware and Midland Basins. Total consideration for the all-stock transaction was valued at $13.1 billion, in which 1.46 shares of ConocoPhillips common stock were exchanged for each outstanding share of Concho common stock.

Total Consideration
Number of shares of Concho common stock issued and outstanding (in thousands)*			194,243
Number of shares of Concho stock awards outstanding (in thousands)*			1,599
Number of shares exchanged			195,842
Exchange ratio			1.46
Additional shares of ConocoPhillips common stock issued as consideration (in thousands)			285,929
Average price per share of ConocoPhillips common stock**			$	45.9025
Total Consideration (Millions)			$	13,125

*Outstanding as of January 15, 2021.

**Based on the ConocoPhillips average stock price on January 15, 2021.

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. Debt assumed in the acquisition was valued based on observable market prices. The fair values determined for accounts receivable, accounts payable, and most other current assets and current liabilities were equivalent to the carrying value due to their short-term nature. The total consideration of $13.1 billion was allocated to the identifiable assets and liabilities based on their fair values as of January 15, 2021.

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Assets Acquired			Millions of Dollars
Cash and cash equivalents			$	382
Accounts receivable, net			745
Inventories			45
Prepaid expenses and other current assets			37
Investments and long-term receivables			333
Net properties, plants and equipment			18,923
Other assets			62
Total assets acquired			$	20,527
Liabilities Assumed
Accounts payable			$	638
Accrued income and other taxes			56
Employee benefit obligations			4
Other accruals			510
Long-term debt			4,696
Asset retirement obligations and accrued environmental costs			310
Deferred income taxes			1,071
Other liabilities and deferred credits			117
Total liabilities assumed			$	7,402
Net assets acquired			$	13,125

With the completion of the Concho transaction, we acquired proved and unproved properties of approximately $11.8 billion and $6.9 billion, respectively.

We recognized approximately $157 million of transaction-related costs, all of which were expensed in the first quarter of 2021. These non-recurring costs related primarily to fees paid to advisors and the settlement of share-based awards for certain Concho employees based on the terms of the Merger Agreement.

In the first quarter of 2021, we commenced a company-wide restructuring program, the scope of which included combining the operations of the two companies as well as other global restructuring activities. We recognized non-recurring restructuring costs mainly for employee severance and related incremental pension benefit costs.

The impact from the transaction and restructuring costs to the lines of our consolidated income statement for the year ended December 31, 2021, are below:

			Millions of Dollars
			Transaction Cost			Restructuring Cost			Total Cost
Production and operating expenses						128			128
Selling, general and administration expenses			135			67			202
Exploration expenses			18			8			26
Taxes other than income taxes			4			2			6
Other expenses			—			29			29
			$	157		234			391

In February 2021, we completed a debt exchange offer related to the debt assumed from Concho. As a result of the debt exchange, we recognized an additional income tax-related restructuring charge of $75 million.

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From the acquisition date through December 31, 2021, “Total Revenues and Other Income” and “Net Income (Loss) Attributable to ConocoPhillips” associated with the acquired Concho business were approximately $6,571 million and $2,330 million, respectively. The results associated with the Concho business for the same period include a before- and after-tax loss of $305 million and $233 million, respectively, on the acquired derivative contracts. The before-tax loss is recorded within “Total Revenues and Other Income” on our consolidated income statement. See Note 12.

Acquisition of Shell Permian Assets

In December 2021, we completed our acquisition of Shell assets in the Permian based Delaware Basin. The accounting close date used for reporting purposes was December 31, 2021. Assets acquired include approximately 225,000 net acres and producing properties located entirely in Texas. Total consideration for the transaction was $8.6 billion.

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 determined for accounts receivable, accounts payable, and most other current assets and current liabilities were equivalent to the carrying value due to their short-term nature. The total consideration of $8.6 billion was allocated to the identifiable assets and liabilities based on their fair values at the acquisition date.

Assets Acquired			Millions of Dollars
Accounts receivable, net			$	337
Inventories			20
Net properties, plants and equipment			8,582
Other assets			50
Total assets acquired			$	8,989
Liabilities Assumed
Accounts payable			$	206
Accrued income and other taxes			6
Other accruals			20
Asset retirement obligations and accrued environmental costs			86
Other liabilities and deferred credits			36
Total liabilities assumed			$	354
Net assets acquired			$	8,635

With the completion of the Shell Permian transaction, we acquired proved and unproved properties of approximately $4.2 billion and $4.3 billion, respectively. We recognized approximately $44 million of transaction-related costs which were expensed in 2021.

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Supplemental Pro Forma (unaudited)

The following tables summarize the unaudited supplemental pro forma financial information for the year ended December 31, 2021, and 2020, as if we had completed the acquisitions of Concho and the Shell Permian assets on January 1, 2020.

			Millions of Dollars
			Year Ended December 31, 2021
			As reported									Pro forma Shell			Pro forma Combined
Total Revenues and Other Income			$	48,349								3,220			51,569
Income (loss) before income taxes			12,712									1,201			13,913
Net Income (Loss) attributable to ConocoPhillips			8,079									920			8,999
Earnings per share:
Basic net income			$	6.09											6.78
Diluted net income			6.07												6.76
			Millions of Dollars
			Year Ended December 31, 2020
			As reported			Pro forma Concho						Pro forma Shell			Pro forma Combined
Total Revenues and Other Income			$	19,256		3,762						1,685			24,703
Income (loss) before income taxes			(3,140)			787						(247)			(2,600)
Net Income (Loss) attributable to ConocoPhillips			(2,701)			498						(189)			(2,392)
Earnings per share:
Basic net loss			$	(2.51)											(1.75)
Diluted net loss			(2.51)												(1.75)

The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the transactions been completed on January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma financial information for the twelve-month period ending December 31, 2020 is a result of combining the consolidated income statement of ConocoPhillips with the results of Concho and the assets acquired from Shell. The pro forma results do not include transaction-related costs, nor any cost savings anticipated as a result of the transactions. The pro forma results include adjustments from Concho’s historical results to reverse impairment expense of $10.5 billion and $1.9 billion related to oil and gas properties and goodwill, respectively. Other adjustments made relate primarily to DD&A, which is based on the unit-of-production method, resulting from the purchase price allocated to properties, plants and equipment. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.

Assets Sold

In 2020, we completed the sale of our Australia-West asset and operations. The sales agreement entitled us to a $200 million payment upon a final investment decision (FID) of the Barossa development project. In March 2021, FID was announced and as such, we recognized a $200 million gain on disposition in the first quarter of 2021. The purchaser failed to pay the FID bonus when due. We have commenced an arbitration proceeding against the purchaser to enforce our contractual right to the $200 million, plus interest accruing from the due date. Results of operations related to this transaction are reflected in our Asia Pacific segment. See Note 11.

In the second half of 2021, we sold our interests in certain noncore assets in our Lower 48 segment for approximately $250 million after customary adjustments, recognizing a before-tax gain on sale of approximately $58 million. We also completed the sale of our noncore exploration interests in Argentina, recognizing a before-tax loss on disposition of $179 million. Results of operations for Argentina were reported in our Other International segment.

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2020

Asset Acquisition

In August 2020, we completed the acquisition of additional Montney acreage in Canada from Kelt Exploration Ltd. for $382 million after customary adjustments, plus the assumption of $31 million in financing obligations associated with partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and included 140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our existing Montney position. The transaction increased our Montney acreage position to approximately 295,000 net acres with a 100 percent working interest. This agreement was accounted for as an asset acquisition resulting in the recognition of $490 million of PP&E; $77 million of ARO and accrued environmental costs; and $31 million of financing obligations recorded primarily to long-term debt. Results of operations for the Montney asset are reported in our Canada segment.

Assets Sold

In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $184 million after customary adjustments. No gain or loss was recognized on the sale. Results of operations for the Waddell Ranch interests sold were reported in our Lower 48 segment.

In March 2020, we completed the sale of our Niobrara interests for approximately $359 million after customary adjustments and recognized a before-tax loss on disposition of $38 million. At the time of disposition, our interest in Niobrara had a net carrying value of $397 million, consisting primarily of $433 million of PP&E and $34 million of ARO. The before-tax loss associated with our interests in Niobrara, including the loss on disposition noted above, was $25 million for the year ended December 31, 2020. Results of operations for the Niobrara interests sold were reported in our Lower 48 segment.

In May 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets and operations, and based on an effective date of January 1, 2019, we received proceeds of $765 million. We recognized a before-tax gain of $587 million related to this transaction in 2020. At the time of disposition, the net carrying value of the subsidiaries sold was approximately $0.2 billion, excluding $0.5 billion of cash. The net carrying value consisted primarily of $1.3 billion of PP&E and $0.1 billion of other current assets offset by $0.7 billion of ARO, $0.3 billion of deferred tax liabilities, and $0.2 billion of other liabilities. The before-tax earnings associated with the subsidiaries sold, including the gain on disposition noted above, was $851 million for the year ended December 31, 2020. The sales agreement entitled us to an additional $200 million upon FID of the Barossa development project. Results of operations for the subsidiaries sold were reported in our Asia Pacific segment.

Note 4—Investments, Loans and Long-Term Receivables

Components of investments and long-term receivables at December 31 were:

			Millions of Dollars
			2022			2021
Equity investments			$	7,493		6,701
Long-term receivables			142			98
Long-term investments in debt securities			522			248
Other investments			68			66
			$	8,225		7,113

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2022, included:

• APLNG—47.5 percent owned joint venture with Origin Energy (27.5 percent) and Sinopec (25 percent)—to produce CBM from the Bowen and Surat basins in Queensland, Australia, as well as process and export LNG.

• Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of QatarEnergy (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field, as well as exports LNG.

• Qatar Liquefied Gas Company Limited (8) (QG8)—25 percent owned joint venture with QatarEnergy (75 percent)—participant in the North Field East (NFE) LNG project. See Note 3.

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Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows:

			Millions of Dollars
			2022			2021			2020
Revenues			$	18,356		11,824			7,931
Income before income taxes			8,234			3,946			1,843
Net income			5,507			2,557			1,426

Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows:

			Millions of Dollars
			2022			2021
Current assets			$	5,001		4,493
Noncurrent assets			37,789			36,602
Current liabilities			4,169			3,498
Noncurrent liabilities			17,244			17,465

Our share of income taxes incurred directly by an equity method investee is reported in equity in earnings of affiliates, and as such is not included in income taxes on our consolidated financial statements.

At December 31, 2022, retained earnings included $42 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $3,045 million, $1,279 million and $1,076 million in 2022, 2021 and 2020, respectively.

APLNG

APLNG is a joint venture focused on producing CBM from the Bowen and Surat basins in Queensland, Australia. Natural gas is sold to domestic customers and LNG is processed and exported to Asia Pacific markets. Our investment in APLNG gives us access to CBM resources in Australia and enhances our LNG position. The majority of APLNG LNG is sold under two long-term sales and purchase agreements, supplemented with sales of additional LNG cargoes targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we operate the LNG facility.

In 2012, APLNG executed an $8.5 billion project finance facility that became non-recourse following financial completion in 2017. The facility is currently composed of a financing agreement with the Export-Import Bank of the United States, a commercial bank facility and two United States Private Placement note facilities. APLNG principal and interest payments commenced in March 2017 and are scheduled to occur bi-annually until September 2030. At December 31, 2022, a balance of $5.2 billion was outstanding on the facilities. See Note 10.

During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was below the carrying value of our existing investment in APLNG. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded in the fourth quarter of 2021 the impairment was other than temporary under the guidance of FASB ASC Topic 323, and the recognition of an impairment of our existing investment was necessary. Accordingly, we recorded a noncash $688 million before-tax and after-tax impairment in the fourth quarter of 2021. The impairment was included in the “Impairments” line on our consolidated income statement. See Note 7.

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At December 31, 2022, the carrying value of our equity method investment in APLNG was approximately $6.2 billion. The historical cost basis of our 47.5 percent share of net assets of APLNG was $6.1 billion, resulting in a basis difference of $41 million on our books. The basis difference, which is substantially all associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to individual production license areas owned by APLNG. Any future additional payments are expected to be allocated in a similar manner. As the joint venture produces natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income (loss) attributable to ConocoPhillips for 2022, 2021 and 2020 was after-tax expense of $10 million, $39 million and $41 million, respectively, representing the amortization of this basis difference on currently producing licenses.

QG3

QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, which was fully repaid in the third quarter of 2022, as described below under “Loans.” At December 31, 2022, the book value of our equity method investment in QG3 was approximately $0.7 billion. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. Currently, the LNG from QG3 is being sold to markets outside of the U.S.

QG8

During 2022, we were awarded a 25 percent interest in a new joint venture (QG8) with QatarEnergy that will participate in the NFE LNG project. QG8 has a 12.5 percent interest in the NFE project. At December 31, 2022, the book value of our equity method investment was approximately $0.3 billion. See Note 3.

Loans

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans to certain affiliated and non-affiliated companies.

At December 31, 2022, there were no outstanding loans to affiliated companies as the final loan payment related to QG3 project financing was received in the third quarter of 2022. QG3 secured project financing of $4.0 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities had substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Semi-annual repayments began in January 2011 and were completed in July 2022, for all loan arrangements.

Note 5—Investment in Cenovus Energy

At December 31, 2021, we held 91 million common shares of Cenovus Energy (CVE), which approximated 4.5 percent of the issued and outstanding common shares of CVE. Those shares were carried on our balance sheet at fair value of $1.1 billion based on NYSE closing price of $12.28 per share on the last day of trading for the period. During the first quarter of 2022, we sold our remaining 91 million shares, recognizing proceeds of $1.4 billion.

All gains and losses were recognized within "Other income (loss)" on our consolidated income statement. Proceeds related to the sale of our CVE shares were included within "Cash Flows from Investing Activities" on our consolidated statement of cash flows. See Note 13.

			Millions of Dollars
			2022			2021			2020
Total Net gain (loss) on equity securities			$	251		1,040			(855)
Less: Net gain (loss) on equity securities sold during the period			251			473
Unrealized gain (loss) on equity securities still held at the reporting date			$			567			(855)

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Note 6—Suspended Wells and Exploration Expenses

The following table reflects the net changes in suspended exploratory well costs during 2022, 2021 and 2020:

			Millions of Dollars
			2022			2021			2020
Beginning balance at January 1			$	660		682			1,020
Additions pending the determination of proved reserves			5			10			164
Reclassifications to proved properties			(7)			—			(42)
Sales of suspended wells			—			—			(313)
Charged to dry hole expense			(131)			(32)			(147)
Ending balance at December 31			$	527		660			682

The following table provides an aging of suspended well balances at December 31:

			Millions of Dollars
			2022			2021			2020
Exploratory well costs capitalized for a period of one year or less			$	15		4			156
Exploratory well costs capitalized for a period greater than one year			512			656			526
Ending balance			$	527		660			682
Number of projects with exploratory well costs capitalized for a period greater than one year			17			22			22

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2022:

			Millions of Dollars
						Suspended Since
			Total			2019-2021			2016-2018			2006-2015
Willow—Alaska(2)			315			201			114			—
PL 1009—Norway(1)			39			39			—			—
PL 891—Norway(1)			31			31			—			—
Narwhal Trend—Alaska(1)			25			—			25			—
WL4-00—Malaysia(2)			24			7			17			—
PL782S—Norway(1)			19			19			—			—
Montney—Canada(1)			12			4			8			—
Other of $10 million or less each(1)(2)			47			7			10			30
Total			$	512		308			174			30

*(1)*Additional appraisal wells planned.

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

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Exploration Expenses

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement.

2022

In the fourth quarter, we recorded a before-tax expense of $129 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 $102 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.

2020

In our Alaska segment, we recorded a before-tax impairment of $828 million for the entire associated carrying value of capitalized undeveloped leasehold costs related to our Alaska North Slope Gas asset. We had stopped participating in evaluating gas line projects and did not believe a project would advance. We remain willing to sell our Alaska North Slope gas to interested parties on a competitive basis if a market materializes in the future.

In our Other International segment, our interests in the Middle Magdalena Basin of Colombia are in force majeure. Because we had no immediate plans to perform under existing contracts, in 2020, we recorded a before-tax expense totaling $84 million for dry hole costs of a previously suspended well and an impairment of the associated capitalized undeveloped leasehold carrying value.

In our Asia Pacific segment, we recorded before-tax expense of $50 million related to dry hole costs of a previously suspended well and an impairment of the associated capitalized undeveloped leasehold carrying value associated with the Kamunsu East Field in Malaysia that is no longer in our development plans.

Note 7—Impairments

During 2022, 2021 and 2020, we recognized the following before-tax impairment charges:

			Millions of Dollars
			2022			2021			2020
Alaska			$	2		5			—
Lower 48			(11)			(8)			804
Canada			(2)			6			3
Europe, Middle East and North Africa			(1)			(24)			6
Asia Pacific			—			695			—
			$	(12)		674			813

2021

We recorded an impairment of $688 million on our APLNG investment included within the Asia Pacific segment. See Note 4 and Note 13.

In our Lower 48 segment, we recorded a credit to impairment of $89 million due to a decreased ARO estimate for a previously sold asset, in which we retained the ARO liability. This was offset by recorded impairments of $84 million during the fourth quarter of 2021, related to certain noncore assets due to changes in development plans. See Note 13.

In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $24 million due to decreased ARO estimates on fields in Norway which ceased production and were fully depreciated in prior years.

2020

We recorded impairments of $813 million, primarily related to certain noncore assets in the Lower 48. Due to a significant decrease in the outlook for current and long-term natural gas prices in early 2020, we recorded impairments of $523 million, primarily for the Wind River Basin operations area, consisting of developed properties in the Madden Field and the Lost Cabin Gas Plant, in the first quarter of 2020. Additionally, due primarily to changes in development plans solidified in the last quarter of 2020, we recognized additional impairments of $287 million in the Lower 48 during the fourth quarter.

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Note 8—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:

			Millions of Dollars
			2022			2021
Asset retirement obligations			$	6,380		5,926
Accrued environmental costs			182			187
Total asset retirement obligations and accrued environmental costs			6,562			6,113
Asset retirement obligations and accrued environmental costs due within one year*			(161)			(359)
Long-term asset retirement obligations and accrued environmental costs			$	6,401		5,754

*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. Reductions to estimated liabilities for assets that are no longer producing are recorded as a credit to 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.

During 2022 and 2021, our overall ARO changed as follows:

			Millions of Dollars
			2022			2021
Balance at January 1			$	5,926		5,573
Accretion of discount			245			238
New obligations			144			555
Changes in estimates of existing obligations			681			(113)
Spending on existing obligations			(231)			(164)
Property dispositions			(203)			(108)
Foreign currency translation			(182)			(55)
Balance at December 31			$	6,380		5,926

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2022 and 2021, were $182 million and $187 million, respectively.

We had accrued environmental costs of $107 million and $135 million at December 31, 2022 and 2021, respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other $59 million and $36 million of environmental costs associated with sites no longer in operation at December 31, 2022 and 2021, respectively. In addition, both December 31, 2022 and 2021, included a $16 million accrual, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.

Expected expenditures for environmental obligations acquired in various business combinations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $111 million at December 31, 2022. The total expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are $147 million.

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Note 9—Debt

Long-term debt at December 31 was:

			Millions of Dollars
			2022			2021
2.40% Notes due 2022			—			329
7.65% Debentures due 2023			78			78
3.35% Notes due 2024			426			426
2.125% Notes due 2024			900			—
8.2% Notes due 2025			134			134
3.35% Debentures due 2025			199			199
2.40% Notes due 2025			900			—
6.875% Debentures due 2026			67			67
4.95% Notes due 2026			—			1,250
7.8% Debentures due 2027			203			203
3.75% Notes due 2027			196			1,000
4.3% Notes due 2028			223			1,000
7.375% Debentures due 2029			92			92
7.0% Debentures due 2029			112			200
6.95% Notes due 2029			1,195			1,549
8.125% Notes due 2030			390			390
7.4% Notes due 2031			382			500
7.25% Notes due 2031			400			500
7.2% Notes due 2031			447			575
2.4% Notes due 2031			227			500
5.9% Notes due 2032			505			505
4.15% Notes due 2034			246			246
5.95% Notes due 2036			326			500
5.951% Notes due 2037			631			645
5.9% Notes due 2038			350			600
6.5% Notes due 2039			1,588			2,750
3.758% Notes due 2042			785			—
4.3% Notes due 2044			750			750
5.95% Notes due 2046			329			500
7.9% Debentures due 2047			60			60
4.875% Notes due 2047			319			800
4.85% Notes due 2048			219			600
3.8% Notes due 2052			1,100			—
4.025% Notes due 2062			1,770			—
Floating rate notes due 2022 at 1.06% – 1.41% during 2022 and 1.02% – 1.12% during 2021			—			500
Marine Terminal Revenue Refunding Bonds due 2031 at 0.07% – 4.10% during 2022 and 0.04% – 0.15% during 2021			265			265
Industrial Development Bonds due 2035 at 0.07% – 4.10% during 2022 and 0.04% – 0.12% during 2021			18			18
Other			23			35
Debt at face value			15,855			17,766
Finance leases			1,320			1,261
Net unamortized premiums, discounts and debt issuance costs			(532)			907
Total debt			16,643			19,934
Short-term debt			(417)			(1,200)
Long-term debt			$	16,226		18,734

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In December 2022, the company retired $329 million principal amount of our 2.40 percent Notes at the natural maturity date. In May 2022, we redeemed $1,250 million principal amount of our 4.95 percent Notes due 2026. We paid premiums above face value of $79 million to redeem the debt and recognized a loss on debt extinguishment of $83 million which is included in the "Other expenses" line on our consolidated income statement. We also paid $500 million to retire the outstanding principal amount of the floating rate notes due 2022 at maturity.

In the first quarter of 2022, we completed a debt refinancing consisting of three concurrent transactions: a tender offer to repurchase existing debt for cash; exchange offers to retire certain debt in exchange for new debt and cash; and a new debt issuance to partially fund the cash paid in the tender and exchange offers.

Tender Offer

In March 2022, we repurchased a total of $2,716 million aggregate principal amount of debt as listed below. We paid premiums above face value of $333 million to repurchase these debt instruments and recognized a gain on debt extinguishment of $155 million which is included in the "Other expenses" line on our consolidated income statement.

• 3.75% Notes due 2027 with principal of $1,000 million (partial repurchase of $804 million)

• 4.3% Notes due 2028 with principal of $1,000 million (partial repurchase of $777 million)

• 2.4% Notes due 2031 with principal of $500 million (partial repurchase of $273 million)

• 4.875% Notes due 2047 with principal of $800 million (partial repurchase of $481 million)

• 4.85% Notes due 2048 with principal of $600 million (partial repurchase of $381 million)

Exchange Offers

Also in March 2022, we completed two concurrent debt exchange offers through which $2,544 million of aggregate principal of existing notes was tendered and accepted in exchange for a combination of new notes and cash. The debt exchange offers were treated as debt modifications for accounting purposes resulting in a portion of the unamortized debt discount, premiums and debt issuance costs of the existing notes being allocated to the new notes on the settlement dates of the exchange offers. We paid premiums above face value of $883 million, comprised of $872 million of cash as well as new notes, which were capitalized as additional debt discount. We incurred expenses of $28 million in the exchanges which are included in the "Other expenses" line on our consolidated income statement.

The notes tendered and accepted in the exchange offers were:

• 7.0% Debentures due 2029 with principal amount of $200 million (partial exchange of $88 million)

• 6.95% Notes due 2029 with principal amount of $1,549 million (partial exchange of $354 million)

• 7.4% Notes due 2031 with principal amount of $500 million (partial exchange of $118 million)

• 7.25% Notes due 2031 with principal amount of $500 million (partial exchange of $100 million)

• 7.2% Notes due 2031 with principal amount of $575 million (partial exchange of $128 million)

• 5.95% Notes due 2036 with principal amount of $500 million (partial exchange of $174 million)

• 5.9% Notes due 2038 with principal amount of $600 million (partial exchange of $250 million)

• 6.5% Notes due 2039 with principal amount of $2,750 million (partial exchange of $1,162 million)

• 5.95% Notes due 2046 with principal amount of $500 million (partial exchange of $171 million)

The notes tendered and accepted were exchanged for the following new notes:

• 3.758% Notes due 2042 with principal amount of $785 million

• 4.025% Notes due 2062 with principal amount of $1,770 million

New Debt Issuance

In March 2022, we issued the following new notes consisting of:

• 2.125% Notes due 2024 with principal of $900 million

• 2.4% Note due 2025 with principal of $900 million

• 3.8% Note due 2052 with principal of $1,100 million

In February 2022, we refinanced our revolving credit facility from a total borrowing capacity of $6.0 billion to $5.5 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 $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.

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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 $5.5 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 no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2022. At December 31, 2021, we had no commercial paper outstanding and no direct borrowings or letters of credit issued.

In January 2021, we completed the acquisition of Concho in an all-stock transaction. In the acquisition, we assumed Concho’s publicly traded debt, with an outstanding principal balance of $3.9 billion, which was recorded at fair value of $4.7 billion on the acquisition date. The adjustment to fair value of the senior notes of approximately $0.8 billion on the acquisition date will be amortized as an adjustment to interest expense over the remaining contractual terms of the senior notes.

In February 2021, we completed a debt exchange offer related to the debt assumed from Concho. Of the approximately $3.9 billion in aggregate principal amount of Concho’s senior notes offered in the exchange, 98 percent, or approximately $3.8 billion, was tendered and accepted. The new debt issued by ConocoPhillips had the same interest rates and maturity dates as the Concho senior notes. The portion not exchanged, approximately $67 million, remained outstanding across five series of senior notes issued by Concho. The debt exchange was treated as a debt modification for accounting purposes resulting in a portion of the unamortized fair value adjustment of the Concho senior notes allocated to the new debt issued by ConocoPhillips on the settlement date of the exchange. The new debt issued in the exchange is fully and unconditionally guaranteed by ConocoPhillips Company. See Note 3.

For information on Finance Leases, see Note 15.

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.

At both December 31, 2022 and 2021, we had $283 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.

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Note 10—Guarantees

At December 31, 2022, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At December 31, 2022, we had outstanding multiple guarantees in connection with our 47.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing December 2022 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 eight years. Our maximum exposure under this guarantee is approximately $210 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At December 31, 2022, the carrying value of this guarantee was approximately $14 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 $780 million ($1.3 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-ventures 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 14 to 23 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $290 million and would become payable if APLNG does not perform. At December 31, 2022, the carrying value of these guarantees was approximately $20 million.

QG8 Guarantee

We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in QG8. This guarantee has an approximate 30-year term with no maximum limit. At December 31, 2022, the carrying value of this guarantee was approximately $7 million.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $600 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 three to four years 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, 2022, there was no carrying value associated with these guarantees.

Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and environmental liabilities. The carrying amount recorded for these indemnifications at December 31, 2022, was approximately $20 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 11 for additional information about environmental liabilities.

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Note 11—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 17, for additional information about income tax-related contingencies.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations and record accruals for environmental liabilities based on management’s best estimates. These estimates are based on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

See Note 8 for a summary of our accrued environmental liabilities.

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Litigation and Other Contingencies

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

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

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2022, we had performance obligations secured by letters of credit of $368 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, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands at $8.5 billion plus interest. The government of Venezuela sought annulment of the award, which automatically stayed enforcement of the award. On September 29, 2021, the ICSID annulment committee lifted the stay of enforcement of the award. The annulment proceedings are underway.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach. As a result, ConocoPhillips has resumed legal enforcement actions. To date, ConocoPhillips has received approximately $774 million in connection with the ICC award. ConocoPhillips has ensured that the settlement and any actions taken in enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.

In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded ConocoPhillips approximately $33 million plus interest under the Corocoro contracts. ConocoPhillips is seeking recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the actions related to the award 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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Beginning in 2017, governmental and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues are unprecedented, therefore, there is significant uncertainty about the scope of the claims and alleged damages and any potential impact on the Company’s financial condition. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.

Several Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips, seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will vigorously defend against them. On October 17, 2022, the Fifth Circuit affirmed remand of lead cases to state court and the subsequent request for rehearing was denied. Accordingly, the federal district courts have issued remands to state court. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages) and we continue to evaluate our exposure in these lawsuits.

In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two 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 25 percent interest in this lease and operated these facilities, but sold its interest approximately 30 years ago. ConocoPhillips continues to evaluate its exposure in this matter.

On May 10, 2021, ConocoPhillips filed arbitration under the rules of the Singapore International Arbitration Centre (SIAC) against Santos KOTN Pty Ltd. and Santos Limited for their failure to timely pay the $200 million bonus due upon FID of the Barossa development project under the sale and purchase agreement. Santos KOTN Pty Ltd. and Santos Limited have filed a response and counterclaim, and the arbitration is underway.

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. We believe the allegations in the action are without merit and are vigorously defending this litigation.

Long-Term Throughput Agreements 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 to be used in the ordinary course of business. The aggregate amounts of estimated payments under these various agreements are: 2023—$7 million; 2024—$7 million; 2025—$7 million; 2026—$7 million; 2027—$7 million; and 2028 and after—$33 million. Total payments under the agreements were $26 million in 2022, $27 million in 2021 and $25 million in 2020.

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Note 12—Derivative and Financial Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs, capture market opportunities and manage foreign exchange currency risk.

Commodity Derivative Instruments

Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and NGLs.

Commodity derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts and certain gas contracts. We do not apply hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

			Millions of Dollars
			2022			2021
Assets
Prepaid expenses and other current assets			$	1,795		1,168
Other assets			242			75
Liabilities
Other accruals			1,800			1,160
Other liabilities and deferred credits			210			63

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:

			Millions of Dollars
			2022			2021			2020
Sales and other operating revenues			$	(88)		(228)			19
Other income (loss)			(5)			25			4
Purchased commodities			(91)			75			11

On January 15, 2021, we assumed financial derivative instruments consisting of oil and natural gas swaps in connection with the acquisition of Concho. At the acquisition date, these financial derivative instruments acquired were recognized at fair value as a net liability of $456 million with settlement dates under the contracts through December 31, 2022. During 2021, we recognized a loss on settlement of these derivatives contracts of $305 million. This loss is recorded within the “Sales and other operating revenues” line on our consolidated income statement. In connection with the settlement, we issued a cash payment of $761 million during 2021 which is included within “Cash Flows From Operating Activities” on our consolidated statement of cash flows.

The table below summarizes our net exposures resulting from outstanding commodity derivative contracts:

			Open Position Long/(Short)
			2022			2021
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price			(14)			4
Basis			(8)			(22)

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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.

The following investments are carried on our consolidated balance sheet at cost, plus accrued interest and the table reflects remaining maturities at December 31, 2022 and 2021:

			Millions of Dollars
			Carrying Amount
			Cash and Cash Equivalents						Short-Term Investments
			2022			2021			2022			2021
Cash			$	593		670
Demand Deposits			1,638			1,554
Time Deposits
1 to 90 days			4,116			2,363			1,288			217
91 to 180 days									883			4
Within one year									11			4
U.S. Government Obligations
1 to 90 days			14			431			—			—
			$	6,361		5,018			2,182			225

The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at December 31, 2022 and 2021:

			Millions of Dollars
			Carrying Amount
			Cash and Cash Equivalents						Short-Term Investments						Investments and Long-Term Receivables
			2022			2021			2022			2021			2022			2021
Major Security Type
Corporate Bonds			$	—		3			323			128			309			173
Commercial Paper			97			7			156			82
U.S. Government Obligations			—			—			115			—			63			2
U.S. Government Agency Obligations									8			2			5			8
Foreign Government Obligations									—			7			7			2
Asset-backed Securities									1			2			138			63
			$	97		10			603			221			522			248

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 five years.

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The following table summarizes the amortized cost basis and fair value of investments in debt securities classified as available for sale at December 31:

			Millions of Dollars
			Amortized Cost Basis						Fair Value
			2022			2021			2022			2021
Major Security Type
Corporate Bonds			$	641		305			632			304
Commercial Paper			253			88			253			89
U.S. Government Obligations			181			2			178			2
U.S. Government Agency Obligations			13			10			13			10
Foreign Government Obligations			7			9			7			9
Asset-backed Securities			139			65			139			65
			$	1,234		479			1,222			479

As of December 31, 2022 and 2021, total unrealized losses for debt securities classified as available for sale with net losses were $12 million and negligible, respectively. No 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, 2022 and 2021, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $644 million and $594 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.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, long-term investments in debt securities, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government money market funds, U.S. government and government agency obligations, time deposits with major international banks and financial institutions, high-quality corporate bonds, foreign government obligations and asset-backed securities. Our long-term investments in debt securities are placed in high-quality corporate bonds, asset-backed securities, U.S. government and government agency obligations, foreign government obligations, and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared primarily with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 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.

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The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position on December 31, 2022 and December 31, 2021, was $333 million and $281 million, respectively. For these instruments, $42 million of collateral was posted as of December 31, 2022 and no collateral was posted as of December 31, 2021. If our credit rating had been downgraded below investment grade on December 31, 2022, we would have been required to post $270 million of additional collateral, either with cash or letters of credit.

Note 13—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the fair value hierarchy.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. There were no material transfers into or out of Level 3 during 2022 or 2021.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in CVE common shares, our investments in debt securities classified as available for sale, and commodity derivatives.

• Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 also includes our investment in common shares of CVE, which is valued using quotes for shares on the NYSE, and our investments in U.S. government obligations classified as available for sale debt securities, which are valued using exchange prices.

• Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 2 also includes our investments in debt securities classified as available for sale including investments in corporate bonds, commercial paper, asset-backed securities, U.S. government agency obligations and foreign government obligations that are valued using pricing provided by brokers or pricing service companies that are corroborated with market data.

• Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

			Millions of Dollars
			December 31, 2022															December 31, 2021
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
Assets
Investment in Cenovus Energy			$															1,117			—			—			1,117
Investments in debt securities			178			1,044			—			1,222						2			477			—			479
Commodity derivatives			958			951			128			2,037						562			619			62			1,243
Total assets			$	1,136		1,995			128			3,259						1,681			1,096			62			2,839
Liabilities
Commodity derivatives			$	906		843			261			2,010						593			543			87			1,223
Total liabilities			$	906		843			261			2,010						593			543			87			1,223

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The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists.

			Millions of Dollars
									Amounts Subject to Right of Setoff
			Gross Amounts Recognized			Amounts Not Subject to Right of Setoff			Gross Amounts			Gross Amounts Offset			Net Amounts Presented			Cash Collateral			Net Amounts
December 31, 2022
Assets			$	2,037		39			1,998			1,176			822			37			785
Liabilities			2,010			20			1,990			1,176			814			52			762
December 31, 2021
Assets			$	1,243		85			1,158			650			508			—			508
Liabilities			1,223			82			1,141			650			491			36			455

At December 31, 2022 and December 31, 2021, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

The following table summarizes the fair value hierarchy by major category and date of remeasurement for assets accounted for at fair value on a non-recurring basis:

			Millions of Dollars
						Fair Value Measurements Using
			Fair Value			Level 1 Inputs			Level 2 Inputs			Level 3 Inputs			Before-Tax Loss
Year ended December 31, 2021
Net PP&E (held for use)
December 31, 2021			$	472		—			—			472			80
Equity Method Investments
December 31, 2021			5,574			—			5,574			—			688

Net PP&E (held for use)

During 2021, the estimated fair value of certain noncore assets included in our Lower 48 segment declined to amounts below the carrying values. The carrying values were written down to fair value. The fair values were estimated based on internal discounted cash flow models using the following estimated assumptions: estimated future production, an outlook of future prices from a combination of exchanges (short-term) coupled with pricing service companies and our internal outlook (long-term), future operating costs and capital expenditures, and a discount rate believed to be consistent with those used by principal market participants. The range and arithmetic average of significant unobservable inputs used in the Level 3 fair value measurements for significant assets were as follows:

			Fair Value (Millions of Dollars)			Valuation Technique			Unobservable Inputs			Range (Arithmetic Average)
December 31, 2021
Lower 48 Gulf Coast and Rockies noncore field			$	472		Discounted cash flow			Commodity production (MBOED)			0.2 - 17 (5.4)
									Commodity price outlook* ($/BOE)			$41.45 - $93.68 ($64.39)
									Discount rate**			7.3% - 9.7% (8.7%)

*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2024-2050; future prices escalated at 2.0% annually after year 2050.

**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

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Equity Method Investments

During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was below the carrying value of our existing investment in APLNG. As such, our investment in APLNG was written down to its fair value of $5,574 million, resulting in a before-tax charge of $688 million. See Note 4 and Note 7.

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. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.

• Investment in Cenovus Energy: See Note 5 for a discussion of the carrying value and fair value of our investment in CVE common shares.

• 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 12.

• Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 4.

• 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.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

			Millions of Dollars
			Carrying Amount									Fair Value
			2022			2021						2022			2021
Financial assets
Investment in CVE common shares			$	—		1,117						$	—		1,117
Commodity derivatives			824			593						824			593
Investments in debt securities			1,222			479						1,222			479
Loans and advances—related parties			—			114						—			114
Financial liabilities
Total debt, excluding finance leases			15,323			18,673						15,545			22,451
Commodity derivatives			782			537						782			537

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Note 14—Equity

Common Stock

The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:

			Shares
			2022			2021			2020
Issued
Beginning of year			2,091,562,747			1,798,844,267			1,795,652,203
Acquisition of Concho			—			285,928,872			—
Distributed under benefit plans			9,322,387			6,789,608			3,192,064
End of year			2,100,885,134			2,091,562,747			1,798,844,267
Held in Treasury
Beginning of year			789,319,875			730,802,089			710,783,814
Repurchase of common stock			87,709,187			58,517,786			20,018,275
End of year			877,029,062			789,319,875			730,802,089

Preferred Stock

We have authorized 500 million shares of preferred stock, par value $0.01 per share, none of which was issued or outstanding at December 31, 2022 or 2021.

Noncontrolling Interests

In 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets and operations. These assets included the Darwin LNG and Bayu-Darwin Pipeline operating joint ventures in which there was a noncontrolling interest. As a result, as of December 31, 2020, we had no noncontrolling interests.

Repurchase of Common Stock

In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of our common stock to support our plan for future share repurchases. In May 2021, we began a paced monetization of our CVE common shares, the proceeds of which have been applied to share repurchases. During the first quarter of 2022, we sold our remaining 91 million CVE common shares. Share repurchases since inception of our current program totaled 335 million shares at a cost of $23 billion through the end of December 2022.

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Note 15—Non-Mineral Leases

The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels, tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices and other leases include payment provisions that vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For additional information about guarantees, see Note 10. There are no significant restrictions imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.

We determine if an arrangement is or contains a lease at contract inception. Certain contractual arrangements may contain both lease and non-lease components. Only the lease components of these contractual arrangements are subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting guidance; however, we have elected to adopt the optional practical expedient not to separate lease components apart from non-lease components for existing asset classes (as of the adoption date of ASC 842) for accounting purposes. For contractual arrangements involving a new leased asset class, we determine at contract inception whether it will apply the optional practical expedient to the new leased asset class.

Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. Future lease payments include variable lease payments that depend upon an index or rate using the index or rate at the commencement date and probable amounts owed under residual value guarantees. The amount of future lease payments may be increased to include additional payments related to lease extension, termination, and/or purchase options when the company has determined, at or subsequent to lease commencement, generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent to the commencement date based on future usage levels, the nature of leased asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with terms of 12 months or less.

We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related joint venture.

The company has historically recorded certain finance leases executed by investee companies accounted for under the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional basis consistent with its ownership interest in the investee company. In addition, the company has historically recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis pursuant to accounting guidance applicable prior to the adoption date of ASC 842 on January 1, 2019. In accordance with the transition provisions of ASC Topic 842, and since we have elected to adopt the package of optional transition-related practical expedients, the historical accounting treatment for these leases has been carried forward and is subject to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term expiration.

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Notes to Consolidated Financial Statements			Table of Contents

The following table summarizes the right-of-use assets and lease liabilities for both the operating and finance leases on our consolidated balance sheet as of December 31:

			Millions of Dollars
			2022						2021
			Operating Leases			Finance Leases			Operating Leases			Finance Leases
Right-of-Use Assets
Properties, plants and equipment
Gross						2,043						1,812
Accumulated DD&A						(1,022)						(857)
Net PP&E*						1,021						955
Prepaid expenses and other current assets									16			2
Other assets			536						649
Lease Liabilities
Short-term debt**						284						280
Other accruals			155						188
Long-term debt***						1,036						981
Other liabilities and deferred credits			390						479
Total lease liabilities			$	545		1,320			667			1,261

** Includes proportionately consolidated finance lease assets of $171 million at December 31, 2022 and $208 million at December 31, 2021.*

*** Includes proportionately consolidated finance lease liabilities of $169 million at December 31, 2022 and $154 million at December 31, 2021.*

**** Includes proportionately consolidated finance lease liabilities of $399 million at December 31, 2022 and $462 million at December 31, 2021.*

The following table summarizes our lease costs:

			Millions of Dollars
			2022			2021			2020
Lease Cost*
Operating lease cost			$	212		278			321
Finance lease cost
Amortization of right-of-use assets			189			148			163
Interest on lease liabilities			32			27			34
Short-term lease cost**			94			21			42
Total lease cost***			$	527		474			560

** 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.*

The following table summarizes the lease terms and discount rates as of December 31:

			2022			2021
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases			5.64			5.97
Finance leases			6.60			7.49
Weighted-average discount rate (percent)
Operating leases			2.99			2.66
Finance leases			3.40			3.24

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The following table summarizes other lease information:

			Millions of Dollars
			2022			2021			2020
Other Information*
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases			$	148		204			232
Operating cash flows from finance leases			30			6			11
Financing cash flows from finance leases			166			73			255
Right-of-use assets obtained in exchange for operating lease liabilities			$	114		174			250
Right-of-use assets obtained in exchange for finance lease liabilities			256			447			426

*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.

The following table summarizes future lease payments for operating and finance leases at December 31, 2022:

			Millions of Dollars
			Operating Leases			Finance Leases
Maturity of Lease Liabilities
2023			$	169		356
2024			126			215
2025			81			210
2026			59			207
2027			46			164
Remaining years			118			352
Total*			599			1,504
Less: portion representing imputed interest			(54)			(184)
Total lease liabilities			$	545		$	1,320

*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee company or oil and gas venture.

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Notes to Consolidated Financial Statements			Table of Contents

Note 16—Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2022									2021									2022			2021
			U.S.			Int’l.						U.S.			Int’l.
Change in Benefit Obligation
Benefit obligation at January 1			$	1,924		4,124						2,548			4,403						137			170
Service cost			58			47						73			61						1			2
Interest cost			62			77						53			79						4			4
Plan participant contributions			—			—						—			—						16			16
Plan amendments			—			—						—			—						9			—
Actuarial (gain) loss			(325)			(847)						(117)			(176)						(27)			(16)
Benefits paid			(241)			(144)						(654)			(162)						(38)			(40)
Divestiture			—			(56)						—			—						—			—
Curtailment			—			—						12			—						—			1
Recognition of termination benefits			—			—						9			—						—			—
Foreign currency exchange rate change			—			(425)						—			(81)						—			—
Benefit obligation at December 31*			$	1,478		2,776						1,924			4,124						102			137
*Accumulated benefit obligation portion of above at December 31:			$	1,384		2,542						1,793			3,658
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1			$	1,664		4,812						1,770			4,793						—			—
Actual return on plan assets			(319)			(1,372)						97			147						—			—
Company contributions			75			96						451			119						22			24
Plan participant contributions			—			1						—			1						16			16
Benefits paid			(241)			(144)						(654)			(162)						(38)			(40)
Divestiture			—			(46)						—			—						—			—
Foreign currency exchange rate change			—			(468)						—			(86)						—			—
Fair value of plan assets at December 31			$	1,179		2,879						1,664			4,812						—			—
Funded Status			$	(299)		103						(260)			688						(102)			(137)

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Notes to Consolidated Financial Statements			Table of Contents

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2022									2021									2022			2021
			U.S.			Int’l.						U.S.			Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets			$	—		373						1			991						—			—
Current liabilities			(28)			(10)						(29)			(15)						(32)			(34)
Noncurrent liabilities			(271)			(260)						(232)			(288)						(70)			(103)
Total recognized			$	(299)		103						(260)			688						(102)			(137)
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate			5.65		%	4.20						2.80			2.15						5.65			2.65
Rate of compensation increase			5.00			3.65						4.00			3.40
Interest crediting rate for applicable benefits			3.55									2.50
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount rate			3.85		%	2.15						2.60			1.80						2.65			2.35
Expected return on plan assets			3.90			2.85						5.20			2.50
Rate of compensation increase			4.00			3.40						4.00			3.40
Interest crediting rate for applicable benefits			2.50									2.10

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 2022 and 2021, the actuarial gains related to the benefit obligations for U.S. and international plans were primarily related to an increase in the discount rates. During 2020, the actuarial losses related to the benefit obligations for U.S. and international plans were primarily related to a decrease in the discount rates.

The following tables summarize information related to the Company's pension plans with projected and accumulated benefit obligations in excess of the fair value of the plans' assets:

			Millions of Dollars
			Pension Benefits
			2022									2021
			U.S.			Int’l.						U.S.			Int’l.
Pension Plans with Projected Benefit Obligation in Excess of Plan Assets
Projected benefit obligation			$	1,478		277						261			362
Fair value of plan assets			1,179			6						—			58
Pension Plans with Accumulated Benefit Obligation in Excess of Plan Assets
Accumulated benefit obligation			$	1,384		239						234			271
Fair value of plan assets			1,179			6						—			9

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Notes to Consolidated Financial Statements			Table of Contents

Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2022									2021									2022			2021
			U.S.			Int’l.						U.S.			Int’l.
Unrecognized net actuarial loss (gain)			$	172		681						188			86						(28)			(1)
Unrecognized prior service cost (credit)			—			1						—			1						(98)			(145)

			Millions of Dollars
			Pension Benefits																		Other Benefits
			2022									2021									2022			2021
			U.S.			Int’l.						U.S.			Int’l.
Sources of Change in Other Comprehensive Income (Loss)
Net gain (loss) arising during the period			$	(44)		(606)						134			207						27			16
Amortization of actuarial loss included in income (loss)*			61			11						145			33						—			—
Net change during the period			$	17		(595)						279			240						27			16
Prior service credit (cost) arising during the period			$	—		(1)						—			—						(9)			—
Amortization of prior service (credit) included in income (loss)			—			(1)						—			(1)						(38)			(37)
Net change during the period			$	—		(2)						—			(1)						(47)			(37)

*Includes settlement (gains) losses recognized in 2022 and 2021.

The components of net periodic benefit cost of all defined benefit plans are presented in the following table:

			Millions of Dollars
			Pension Benefits																											Other Benefits
			2022									2021									2020									2022			2021			2020
			U.S.			Int’l.						U.S.			Int’l.						U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost			$	58		47						73			61						85			54						1			2			2
Interest cost			62			77						53			79						66			85						4			4			6
Expected return on plan assets			(50)			(124)						(80)			(120)						(85)			(145)						—			—			—
Amortization of prior service credit			—			(1)						—			(1)						—			(1)						(38)			(37)			(31)
Recognized net actuarial loss (gain)			24			11						43			33						51			22						—			—			1
Settlements loss (gain)			37			—						102			—						44			(1)						—			—			—
Curtailment loss			—			—						12			—						—			—						—			—			—
Net periodic benefit cost			$	131		10						203			52						161			14						(33)			(31)			(22)

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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Notes to Consolidated Financial Statements			Table of Contents

We recognized pension settlement losses of $37 million in 2022, $102 million in 2021, and $43 million in 2020 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 10 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 6.5 percent in 2023 that declines to 5 percent by 2029. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2023 that increases to 5 percent by 2029.

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 are 25 percent equity securities, 71 percent debt securities, and 4 percent real estate. 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, 2022 and 2021.

• 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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• A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract, which is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participating interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted market prices, recently executed transactions, and an actuarial present value computation for contract obligations. At December 31, 2022, the participating interest in the annuity contract was valued at $55 million and consisted of $144 million in debt securities, less $89 million for the accumulated benefit obligation covered by the contract. At December 31, 2021, the participating interest in the annuity contract was valued at $83 million and consisted of $206 million in debt securities, less $123 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.

The fair values of our pension plan assets at December 31, by asset class were as follows:

			Millions of Dollars
			U.S.															International
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
2022
Equity securities
U.S.			$	4		—			—			4						—			—			—			—
International			36			—			—			36						—			—			—			—
Mutual funds			14			—			—			14						201			298			—			499
Debt securities
Corporate			—			1			—			1						—			—			—			—
Mutual funds			—			—			—			—						365			—			—			365
Cash and cash equivalents			—			—			—			—						36			—			—			36
Real estate			—			—			—			—						—			—			146			146
Total in fair value hierarchy			$	54		1			—			55						602			298			146			1,046
Investments measured at net asset value*
Equity securities
Common/collective trusts												265															192
Debt securities
Common/collective trusts												759															1,637
Cash and cash equivalents												10															—
Real estate												34															—
Total**			$	54		1			—			1,123						602			298			146			2,875

*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 $55 million and net receivables related to security transactions of $5 million.

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The fair values of our pension plan assets at December 31, by asset class were as follows:

			Millions of Dollars
			U.S.															International
			Level 1			Level 2			Level 3			Total						Level 1			Level 2			Level 3			Total
2021
Equity securities
U.S.			$	3		—			5			8						—			—			—			—
International			42			—			—			42						—			—			—			—
Mutual funds			17			—			—			17						236			403			—			639
Debt securities
Corporate			—			1			—			1						—			—			—			—
Mutual funds			—			—			—			—						511			—			—			511
Cash and cash equivalents			—			—			—			—						68			—			—			68
Derivatives			—			—			—			—						—			—			—			—
Real estate			—			—			—			—						—			—			157			157
Total in fair value hierarchy			$	62		1			5			68						815			403			157			1,375
Investments measured at net asset value*
Equity securities
Common/collective trusts												394															417
Debt securities
Common/collective trusts												1,073															3,015
Cash and cash equivalents												9															—
Real estate												36															1
Total**			$	62		1			5			1,580						815			403			157			4,808

*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 $83 million and net receivables related to security transactions of $5 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 2023, we expect to contribute approximately $90 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $45 million to our international qualified and nonqualified pension and postretirement benefit plans.

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The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid:

			Millions of Dollars
			Pension Benefits									Other Benefits
			U.S.			Int’l.
2023			$	216		121						17
2024			199			123						15
2025			188			125						14
2026			173			126						12
2027			171			128						11
2028–2032			685			677						38

The following table summarizes our severance accrual activity:

			Millions of Dollars
			2022			2021			2020
Balance at January 1			$	78		24			23
Accruals			1			170			14
Benefit payments			(48)			(116)			(13)
Balance at December 31			$	31		78			24

Accruals include severance costs associated with our company-wide restructuring program. Of the remaining balance at December 31, 2022, $19 million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of 17 investment options. Employees who participate in the CPSP and contribute 1 percent of their eligible pay receive a 6 percent company cash match with a potential company discretionary cash contribution of up to 6 percent. Effective January 1, 2019, new employees, rehires and employees that elected to opt out of Title II of the ConocoPhillips Retirement Plan are eligible to receive a Company Retirement Contribution (CRC) of 6 percent of eligible pay into their CPSP. After three years of service with the company, the employee is 100 percent vested in any CRC. Company contributions charged to expense for the CPSP and predecessor plans were $140 million in 2022, $93 million in 2021 and $62 million in 2020.

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 $24 million in 2022, $26 million in 2021 and $25 million in 2020.

Share-Based Compensation Plans

The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2014, replacing similar prior plans and providing that no new awards shall be granted under the prior plans. Over its 10-year life, the Plan allows the issuance of up to 79 million shares of our common stock for compensation to our employees and directors; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the 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 shall be available for awards under the Plan. Of the 79 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options. 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, restricted stock units and performance share units to employees and non-employee directors who contribute to the company’s continued success and profitability.

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Total share-based compensation expense is measured using the grant date fair value for our equity-classified awards and the settlement date fair value for our liability-classified awards. We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture. Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). We recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Compensation Expense—Total share-based compensation expense recognized in net income (loss) and the associated tax benefit were:

			Millions of Dollars
			2022			2021			2020
Compensation cost			$	377		304			159
Tax benefit			95			76			40

Stock Options—Stock options granted under the provisions of the 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 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to certain employees already eligible for retirement vest within six months 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 and replaced with three-year, time-vested restricted stock units which generally will be cash-settled for 2018 and 2019 awards and stock-settled beginning with 2020 awards.

The following summarizes our stock option activity for the year ended December 31, 2022:

															Millions of Dollars
			Options						Weighted-Average Exercise Price						Aggregate Intrinsic Value
Outstanding at December 31, 2021			11,973,783						$	56.46					$	188
Exercised			(7,670,208)						57.12						(308)
Expired or cancelled			—						—
Outstanding at December 31, 2022			4,303,575						$	55.28					$	266
Vested at December 31, 2022			4,303,575						$	55.28					$	266
Exercisable at December 31, 2022			4,303,575						$	55.28					$	266

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2022, were all 2.57 years. The aggregate intrinsic value of options exercised was $68 million in 2021 and $23 million in 2020.

During 2022, we received $438 million in cash and realized a tax benefit of $59 million from the exercise of options. At December 31, 2022, all outstanding stock options were fully vested and there was no remaining compensation cost to be recorded.

Stock Unit Program—Generally, restricted stock units (RSU) are granted annually under the provisions of the Plan and vest in an aggregate installment on the third anniversary of the grant date. In addition, RSUs granted under the Plan for a variable long-term incentive program vest ratably in three equal annual installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award.

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Stock-Settled

Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units are not issued as common stock until the earlier of separation from the company or the end of the regularly scheduled vesting period. Until issued as stock, most recipients of the RSUs receive a cash payment of a dividend equivalent or an accrued reinvested dividend equivalent that is charged to retained earnings. The grant date fair market value of these RSUs is deemed equal to the average ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.

The following summarizes our stock-settled stock unit activity for the year ended December 31, 2022:

			Stock Units						Weighted-Average Grant Date Fair Value						Millions of Dollars
									Total Fair Value
Outstanding at December 31, 2021			7,645,311						$	53.81
Granted			2,139,168						90.57
Forfeited			(137,011)						71.38
Issued			(2,069,275)						63.57						$	193
Outstanding at December 31, 2022			7,578,193						$	61.20
Not Vested at December 31, 2022			5,264,282						$	61.58

At December 31, 2022, the remaining unrecognized compensation cost from the unvested stock-settled units was $135 million, which will be recognized over a weighted-average period of 1.67 years, the longest period being 2.67 years. The weighted-average grant date fair value of stock unit awards granted during 2021 and 2020 was $46.56 and $57.40, respectively. The total fair value of stock units issued during 2021 and 2020 was $144 million and $143 million, respectively.

Cash-Settled

Cash settled executive restricted stock units granted in 2018 and 2019 replaced the stock option program. These restricted stock units, subject to elections to defer, 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. Units awarded to retirement eligible employees vest six months from the grant date; however, those units are not settled until the earlier of separation from the company or the end of the regularly scheduled vesting 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 settlement date. Recipients 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. Beginning with executive restricted stock units granted in 2020, awards will be settled in stock.

The following summarizes our cash-settled stock unit activity for the year ended December 31, 2022:

			Stock Units						Weighted-Average Grant Date Fair Value						Millions of Dollars
									Total Fair Value
Outstanding at December 31, 2021			226,476						$	72.18
Granted			531						85.37
Forfeited			—						—
Issued			(227,007)						91.47						$	21
Outstanding at December 31, 2022			—						$	—

At December 31, 2022, there was no remaining unrecognized compensation cost to be recorded for the unvested cash-settled units. The weighted-average grant date fair value of stock unit awards granted during 2021 and 2020 were $57.19 and $41.59, respectively. The total fair value of stock units issued during 2021 and 2020 were $20 million and negligible, respectively.

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Performance Share Program—Under the Plan, we also annually grant restricted performance share units (PSUs) to senior management. These PSUs are authorized three years 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.

Stock-Settled

For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for retirement by reaching age 55 with five years 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 five years of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or five years 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. Since these awards are authorized three years 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 PSUs receive a cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants will vest, absent employee election to defer, upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share of ConocoPhillips common stock per unit.

The following summarizes our stock-settled Performance Share Program activity for the year ended December 31, 2022:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2021			1,448,847						$	50.69
Granted			1,754						91.58
Issued			(218,986)						51.04						$	21
Outstanding at December 31, 2022			1,231,615						$	50.68

At December 31, 2022, there was no remaining unrecognized compensation cost to be recorded on the unvested stock-settled performance shares. There were no stock-settled PSUs granted during 2021; however, the weighted-average grant date fair value of stock-settled PSUs granted during 2020 was $58.61. The total fair value of stock-settled PSUs issued during 2021 and 2020 were $18 million and $13 million, respectively.

Cash-Settled

In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent employee election to defer, on the earlier of five years 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, PSUs authorized for future grants will vest upon settlement following the conclusion of the three-year 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 period beginning in 2018, 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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The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2022:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2021			117,679						$	72.18
Granted			967,151						91.58
Settled			(975,007)						89.87						$	88
Outstanding at December 31, 2022			109,823						$	117.11

At December 31, 2022, all outstanding cash-settled performance awards were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs granted during 2021 and 2020 was $46.65 and $58.61, respectively. The total fair value of cash-settled performance share awards settled during 2021 and 2020 was $52 million and $116 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 three-year 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 three-year 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 restricted stock units 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, as part of an executive compensation program that has been discontinued or acquired as a result of an acquisition. Generally, the recipients of the restricted shares or units receive a dividend or dividend equivalent.

The following summarizes the aggregate activity of these restricted shares and units for the year ended December 31, 2022:

									Weighted-Average Grant Date Fair Value						Millions of Dollars
			Stock Units									Total Fair Value
Outstanding at December 31, 2021			1,616,367						$	47.24
Granted			73,450						96.20
Cancelled			(1,030)						24.61
Issued			(449,028)						48.28						$	40
Outstanding at December 31, 2022			1,239,759						$	49.78
Not Vested at December 31, 2022			437,994						$	45.90

At December 31, 2022, the remaining compensation cost from the unvested restricted stock was $10 million, which will be recognized over a weighted-average period of 1 year. The weighted-average grant date fair value of awards granted during 2021 and 2020 was $46.43 and $51.46, respectively. The total fair value of awards issued during 2021 and 2020 was $8 million and $6 million, respectively.

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Note 17—Income Taxes

Components of income tax provision (benefit) were:

			Millions of Dollars
			2022						2021						2020
Income Taxes
Federal
Current			$	1,263					32						3
Deferred			1,629						1,161						(625)
Foreign
Current			5,813						3,128						350
Deferred			387						66						(70)
State and local
Current			386						127						(4)
Deferred			70						119						(139)
Total tax provision (benefit)			$	9,548					4,633						(485)

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:

			Millions of Dollars
			2022			2021
Deferred Tax Liabilities
PP&E and intangibles			$	11,100		10,170
Inventory			48			44
Other			190			213
Total deferred tax liabilities			11,338			10,427
Deferred Tax Assets
Benefit plan accruals			450			321
Asset retirement obligations and accrued environmental costs			2,333			2,297
Investments in joint ventures			1,917			1,684
Other financial accruals and deferrals			736			827
Loss and credit carryforwards			6,354			7,402
Other			112			399
Total deferred tax assets			11,902			12,930
Less: valuation allowance			(8,049)			(8,342)
Total deferred tax assets net of valuation allowance			3,853			4,588
Net deferred tax liabilities			$	7,485		5,839

At December 31, 2022, noncurrent assets and liabilities included deferred taxes of $241 million and $7,726 million, respectively. At December 31, 2021, noncurrent assets and liabilities included deferred taxes of $340 million and $6,179 million, respectively.

At December 31, 2022, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign tax credit carryforwards of $5.3 billion and various jurisdictions net operating loss and credit carryforwards of $1.1 billion. If not utilized, U.S. foreign tax credits and net operating losses will begin to expire in 2023.

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The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance for 2022, 2021 and 2020:

			Millions of Dollars
			2022			2021			2020
Balance at January 1			$	8,342		9,965			10,214
Charged to expense (benefit)			5			(45)			460
Other*			(298)			(1,578)			(709)
Balance at December 31			$	8,049		8,342			9,965

*Represents changes due to originating 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, 2022, 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 2022, the valuation allowance movement charged to earnings primarily relates 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.

During the second quarter of 2022, Norway enacted changes to the Petroleum Tax System. As a result of the enactment, a valuation allowance of $58 million was recorded during the second quarter to reflect changes to our ability to realize certain deferred tax assets under the new law.

During 2021, the valuation allowance movement charged to earnings primarily relates to the fair value measurement of our CVE common shares that are not expected to be realized, and the expected realization of certain U.S. tax attributes associated with our planned disposition of our Indonesia assets. This is partially offset by Australian tax benefits associated with our impairment of APLNG that we do not expect to be realized. Other movements are primarily related to valuation allowances on expiring tax attributes. For more information on our Indonesia disposition see Note 3.

During 2020, the valuation allowance movement charged to earnings primarily related to capital losses in Australia and to the fair value measurement of our CVE common shares that are not expected to be realized. Other movements are primarily related to valuation allowances on expiring tax attributes.

At December 31, 2022, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $4,477 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 $224 million.

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The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2022, 2021 and 2020:

			Millions of Dollars
			2022			2021			2020
Balance at January 1			$	1,345		1,206			1,177
Additions based on tax positions related to the current year			6			15			6
Additions for tax positions of prior years			6			177			67
Reductions for tax positions of prior years			(62)			(5)			(34)
Settlements			(510)			—			(9)
Lapse of statute			(75)			(48)			(1)
Balance at December 31			$	710		1,345			1,206

Included in the balance of unrecognized tax benefits for 2022, 2021 and 2020 were $701 million, $1,261 million and $1,128 million respectively, which, if recognized, would impact our effective tax rate. The balance of the unrecognized tax benefits decreased 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 $515 million relating to the recovery of outside tax basis previously offset by a full reserve. The balance of the unrecognized tax benefits increased in 2021 mainly due to U.S. tax credits acquired through our Concho acquisition. See Note 3 and Note 11.

At December 31, 2022, 2021 and 2020, accrued liabilities for interest and penalties totaled $35 million, $47 million and $46 million, respectively, net of accrued income taxes. Interest and penalties resulted in an increase to earnings of $12 million in 2022, a reduction of $1 million in 2021 and a reduction to earnings of $4 million in 2020.

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 (2021) and U.S. (2018). 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.

The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate to the provision for income taxes, were:

			Millions of Dollars												Percent of Pre-Tax Income (Loss)
			2022			2021			2020						2022			2021			2020
Income (loss) before income taxes
United States			$	16,739		8,024			(3,587)						59.3		%	63.1			114.2
Foreign			11,489			4,688			447						40.7			36.9			(14.2)
			$	28,228		12,712			(3,140)						100.0		%	100.0			100.0
Federal statutory income tax			$	5,928		2,670			(659)						21.0		%	21.0			21.0
Non-U.S. effective tax rates			3,866			1,915			194						13.7			15.1			(6.2)
Australia disposition			—			—			(349)						—			—			11.1
Recovery of outside basis			(30)			(55)			(22)						(0.1)			(0.4)			0.7
Adjustment to tax reserves			(551)			(11)			18						(2.0)			(0.1)			(0.6)
Adjustment to valuation allowance			5			(45)			460						—			(0.4)			(14.6)
State income tax			405			194			(112)						1.4			1.5			3.6
Enhanced oil recovery credit			(37)			(99)			(6)						(0.1)			(0.8)			0.2
Other			(38)			64			(9)						(0.1)			0.5			0.3
Total			$	9,548		4,633			(485)						33.8		%	36.4			15.5

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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.

Our effective tax rate for 2021 was driven by our jurisdictional tax rates for this profit mix with net favorable impacts from routine tax credits and valuation allowance adjustments. The valuation allowance adjustment is primarily related to the fair value measurement and disposition of our CVE common shares of $218 million and the ability to utilize the U.S. foreign tax credit and capital loss carryforward due to our anticipated disposition of our Indonesia entities of $29 million. This was partially offset by an increase to our valuation allowance related to the tax impact of the impairment of our APLNG investment of $206 million for which we do not expect to receive a tax benefit.

Our effective tax rate for 2020 was impacted by the disposition of our Australia-West assets as well as the valuation allowance related to the fair value measurement of our CVE common shares. The Australia-West disposition generated a before-tax gain of $587 million with an associated tax benefit of $10 million and resulted in the de-recognition of deferred tax assets resulting in $92 million of tax expense. The disposition also generated an Australia capital loss tax benefit of $313 million which has been fully offset by a valuation allowance. Due to changes in the fair market value of CVE common shares, the valuation allowance was increased by $178 million to offset the expected capital loss.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022, which among other things, implements a 15 percent minimum tax on book income of certain large corporations, a 1 percent excise tax on net stock repurchases and several tax incentives to promote lower carbon energy. We are continuing to evaluate the impacts of this legislation as additional guidance is released; however, we do not believe any impacts will be material to our consolidated financial statements.

Note 18—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss in the equity section of the balance sheet included:

			Millions of Dollars
			Defined Benefit Plans			Net Unrealized Gain/(Loss) on Securities			Foreign Currency Translation			Accumulated Other Comprehensive Loss
December 31, 2019			$	(350)		—			(5,007)			(5,357)
Other comprehensive income (loss)			(75)			2			212			139
December 31, 2020			(425)			2			(4,795)			(5,218)
Other comprehensive income (loss)			394			(2)			(124)			268
December 31, 2021			(31)			—			(4,919)			(4,950)
Other comprehensive income (loss)			(417)			(11)			(622)			(1,050)
December 31, 2022			$	(448)		(11)			(5,541)			(6,000)

The following table summarizes reclassifications out of accumulated other comprehensive loss during the years ended December 31:

			Millions of Dollars
			2022			2021
Defined Benefit Plans			$	26		109
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:			$	7		31
See Note 16.

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Note 19—Cash Flow Information

			Millions of Dollars
			2022			2021			2020
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations			$	825		442			(116)
Cash Payments
Interest			$	873		924			785
Income taxes			7,368			856			905
Net Sales (Purchases) of Investments
Short-term investments purchased			$	(5,046)		(5,554)			(12,435)
Short-term investments sold			3,102			8,810			12,015
Investments and long-term receivables purchased			(775)			(279)			(325)
Investments and long-term receivables sold			90			114			87
			$	(2,629)		3,091			(658)

Income tax payments have increased in 2022 as the company is returning to a tax paying position in the U.S. as well as, increased taxes in Norway, and timing of tax payments in Libya.

See Note 3 and Note 12 for additional information on cash and non-cash changes to our consolidated balance sheet associated with our Concho acquisition.

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Note 20—Other Financial Information

			Millions of Dollars
			2022			2021			2020
Interest and Debt Expense
Incurred
Debt			$	791		887			788
Other			72			59			73
			863			946			861
Capitalized			(58)			(62)			(55)
Expensed			$	805		884			806
Other Income (Loss)
Interest income			$	195		33			100
Gain (loss) on investment in Cenovus Energy*			251			1,040			(855)
Other, net			58			130			246
			$	504		1,203			(509)
*See Note 5.
**Research and Development Expenditures—**expensed			$	71		62			75
Shipping and Handling Costs			$	1,595		1,047			857
**Foreign Currency Transaction (Gains) Losses—**after-tax
Alaska			$	—		—			—
Lower 48			—			—			—
Canada			(20)			(1)			(7)
Europe, Middle East and North Africa			(110)			(11)			(15)
Asia Pacific			30			2			(11)
Other International			(1)			1			2
Corporate and Other			21			(7)			(31)
			$	(80)		(16)			(62)

			Millions of Dollars
			2022			2021
Properties, Plants and Equipment
Proved properties			$	119,609		114,274			*
Unproved properties			7,325			10,993
Other			4,562			4,379
Gross properties, plants and equipment			131,496			129,646
Less: Accumulated depreciation, depletion and amortization			(66,630)			(64,735)			*
Net properties, plants and equipment			$	64,866		64,911

*Excludes assets classified as held for sale at December 31, 2021. See Note 3.

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Note 21—Related Party Transactions

Our related parties primarily include equity method investments and certain trusts for the benefit of employees. For disclosures on trusts for the benefit of employees, see Note 16.

Significant transactions with our equity affiliates were:

			Millions of Dollars
			2022			2021			2020
Operating revenues and other income			$	88		88			79
Purchases			1			5			—
Operating expenses and selling, general and administrative expenses			189			196			63
Net interest income*			(1)			(2)			(5)

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

Note 22—Sales and Other Operating Revenues

Revenue from Contracts with Customers

The following table provides further disaggregation of our consolidated sales and other operating revenues:

			Millions of Dollars
			2022			2021			2020
Revenue from contracts with customers			$	61,049		34,590			13,662
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative			17,150			11,500			5,177
Financial derivative contracts			295			(262)			(55)
Consolidated sales and other operating revenues			$	78,494		45,828			18,784

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 24—Segment Disclosures and Related Information:

			Millions of Dollars
			2022			2021			2020
Revenue from Outside the Scope of ASC Topic 606 by Segment
Lower 48			$	13,919		9,050			3,966
Canada			2,717			1,457			727
Europe, Middle East and North Africa			514			993			484
Physical contracts meeting the definition of a derivative			$	17,150		11,500			5,177

			Millions of Dollars
			2022			2021			2020
Revenue from Outside the Scope of ASC Topic 606 by Product
Crude oil			$	495		757			395
Natural gas			15,368			10,034			4,339
Other			1,287			709			443
Physical contracts meeting the definition of a derivative			$	17,150		11,500			5,177

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Practical Expedients

Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific cases may extend longer, which may be out to the end of field life. We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the reporting period.

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At December 31, 2022, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $5,241 million compared with $5,268 million at December 31, 2021, 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 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 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. During the year ended December 31, 2022, we recognized revenue of $57 million in the "Sales and other operating revenues" line on our consolidated income statement. We expect to recognize the outstanding contract liabilities of $19 million as of December 31, 2022, as revenue during 2026.

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Note 23—Earnings Per Share

The following table presents the calculation of net income available to common shareholders and basic and diluted EPS for the years ended December 31, 2022, 2021, and 2020. For each of the periods with net income presented in the table below, diluted EPS calculated under the two-class method was more dilutive.

			Millions of Dollars (except per share amounts)
Years Ended December 31			2022			2021			2020
Basic earnings per share
Net Income (Loss) Attributable to ConocoPhillips			$	18,680		8,079			(2,701)
Less: Dividends and undistributed earnings
allocated to participating securities			60			19			6
Net Income (Loss) available to common shareholders			$	18,620		8,060			(2,707)
Average common shares outstanding (in Millions)			1,274			1,324			1,078
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock			$	14.62		6.09			(2.51)
Diluted earnings per share
Net Income (Loss) available to common shareholders			$	18,620		8,060			(2,707)
Average common shares outstanding (in Millions)			1,274			1,324			1,078
Add: Dilutive impact of options and unvested
non-participating RSU/PSUs			4			4			—
Average diluted shares outstanding (in Millions)			1,278			1,328			1,078
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock			$	14.57		6.07			(2.51)

Note 24—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.

Corporate and Other 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.

We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1. Intersegment sales are at prices that approximate market.

In 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production company with operations across New Mexico and West Texas as well as our acquisition of Shell’s Permian assets in the Texas Delaware Basin. The accounting close date of the Shell transaction, used for reporting purposes, was December 31, 2021. Results of operations for Concho and assets acquired from Shell are included in our Lower 48 segment. Certain transaction and restructuring costs associated with these acquisitions are included in our Corporate and Other segment. See Note 3.

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Analysis of Results by Operating Segment

			Millions of Dollars
			2022			2021			2020
Sales and Other Operating Revenues
Alaska			$	7,905		5,480			3,408
Intersegment eliminations			—			—			(11)
Alaska			7,905			5,480			3,397
Lower 48			52,921			29,306			9,872
Intersegment eliminations			(18)			(12)			(51)
Lower 48			52,903			29,294			9,821
Canada			6,159			4,077			1,666
Intersegment eliminations			(2,445)			(1,583)			(405)
Canada			3,714			2,494			1,261
Europe, Middle East and North Africa			11,271			5,902			1,919
Intersegment eliminations			(1)			—			(2)
Europe, Middle East and North Africa			11,270			5,902			1,917
Asia Pacific			2,606			2,579			2,363
Other International			—			4			7
Corporate and Other			96			75			18
Consolidated sales and other operating revenues			$	78,494		45,828			18,784

The market for our products is large and diverse, therefore, our sales and other operating revenues are not dependent upon any single customer.

			Millions of Dollars
			2022			2021			2020
Depreciation, Depletion, Amortization and Impairments
Alaska			$	941		1,002			996
Lower 48			4,854			4,067			3,358
Canada			400			392			342
Europe, Middle East and North Africa			735			862			775
Asia Pacific			518			1,483			809
Other International			—			—			—
Corporate and Other			44			76			54
Consolidated depreciation, depletion, amortization and impairments			$	7,492		7,882			6,334

Equity in Earnings of Affiliates
Alaska			$	4		5			(7)
Lower 48			(14)			(18)			(11)
Canada			—			—			—
Europe, Middle East and North Africa			780			502			311
Asia Pacific			1,310			343			137
Other International			1			—			2
Corporate and Other			—			—			—
Consolidated equity in earnings of affiliates			$	2,081		832			432

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			Millions of Dollars
			2022			2021			2020
Income Tax Provision (Benefit)
Alaska			$	885		402			(256)
Lower 48			3,088			1,390			(378)
Canada			206			150			(185)
Europe, Middle East and North Africa			5,445			2,543			136
Asia Pacific			480			483			294
Other International			53			(53)			(20)
Corporate and Other			(609)			(282)			(76)
Consolidated income tax provision (benefit)			$	9,548		4,633			(485)

Net Income (Loss) Attributable to ConocoPhillips
Alaska			$	2,352		1,386			(719)
Lower 48			11,015			4,932			(1,122)
Canada			714			458			(326)
Europe, Middle East and North Africa			2,244			1,167			448
Asia Pacific			2,736			453			962
Other International			(51)			(107)			(64)
Corporate and Other			(330)			(210)			(1,880)
Consolidated net income (loss) attributable to ConocoPhillips			$	18,680		8,079			(2,701)

Investments in and Advances to Affiliates
Alaska			$	55		58			62
Lower 48			235			242			25
Canada			—			—			—
Europe, Middle East and North Africa			1,049			797			918
Asia Pacific			6,154			5,603			6,705
Other International			—			1			—
Corporate and Other			—			—			—
Consolidated investments in and advances to affiliates			$	7,493		6,701			7,710

Total Assets
Alaska			$	15,126		14,812			14,623
Lower 48			42,950			41,699			11,932
Canada			6,971			7,439			6,863
Europe, Middle East and North Africa			8,263			9,125			8,756
Asia Pacific			9,511			9,840			11,231
Other International			—			1			226
Corporate and Other			11,008			7,745			8,987
Consolidated total assets			$	93,829		90,661			62,618

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			Millions of Dollars
			2022			2021			2020
Capital Expenditures and Investments
Alaska			$	1,091		982			1,038
Lower 48			5,630			3,129			1,881
Canada			530			203			651
Europe, Middle East and North Africa			998			534			600
Asia Pacific			1,880			390			384
Other International			—			33			121
Corporate and Other			30			53			40
Consolidated capital expenditures and investments			$	10,159		5,324			4,715

Interest Income and Expense
Interest income
Alaska			$	—		—			—
Lower 48			—			—			—
Canada			—			—			—
Europe, Middle East and North Africa			1			2			5
Asia Pacific			9			9			7
Other International			—			—			—
Corporate and Other			185			22			88
Interest and debt expense
Corporate and Other			$	805		884			806

Sales and Other Operating Revenues by Product
Crude oil			$	41,492		23,648			9,736
Natural gas			26,941			16,904			6,427
Natural gas liquids			3,650			1,668			528
Other*			6,411			3,608			2,093
Consolidated sales and other operating revenues by product			$	78,494		45,828			18,784

*Includes LNG and bitumen.

Geographic Information

			Millions of Dollars
			Sales and Other Operating Revenues(1)												Long-Lived Assets(2)
			2022			2021			2020						2022			2021			2020
United States			$	60,899		34,847			13,230						51,200			50,580			24,034
Australia and Timor-Leste			—			—			605						6,158			5,579			6,676
Canada			3,714			2,494			1,261						6,269			6,608			6,385
China			1,135			724			460						1,538			1,476			1,491
Indonesia(3)			159			879			689						—			28			464
Libya			1,582			1,102			155						714			659			670
Malaysia			1,312			975			610						1,107			1,252			1,501
Norway			3,415			2,563			1,426						4,369			4,681			5,294
United Kingdom			6,273			2,236			336						1			1			1
Other foreign countries			5			8			12						1,003			748			1,087
Worldwide consolidated			$	78,494		45,828			18,784						72,359			71,612			47,603

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

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

*(3)*Assets divested in 2022. See Note 3**.

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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, 2022, approximately 3 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 4 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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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 units’ 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 2022, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2022, 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, 2022, 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 petroleum engineering. He is a member of the Society of Petroleum Engineers with over 30 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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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			Equity Affiliates*			Total
Developed and Undeveloped
End of 2019			1,231			797			2,028			5			198			134			197			2,562			73			2,635
Revisions			(297)			(126)			(423)			(2)			4			(4)			(3)			(428)			—			(428)
Improved recovery			—			—			—			—			—			3			—			3			—			3
Purchases			—			5			5			3			—			—			—			8			—			8
Extensions and discoveries			10			108			118			3			—			—			—			121			—			121
Production			(65)			(77)			(142)			(2)			(28)			(25)			(3)			(200)			(5)			(205)
Sales			—			(14)			(14)			(1)			—			—			—			(15)			—			(15)
End of 2020			879			693			1,572			6			174			108			191			2,051			68			2,119
Revisions			209			(52)			157			2			14			37			6			216			—			216
Improved recovery			1			—			1			—			—			—			—			1			—			1
Purchases			—			691			691			—			—			—			—			691			—			691
Extensions and discoveries			10			289			299			5			2			1			—			307			—			307
Production			(64)			(160)			(224)			(3)			(29)			(24)			(13)			(293)			(5)			(298)
Sales			—			(9)			(9)			—			—			—			—			(9)			—			(9)
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

Years Ended December 31			Crude Oil
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total Consolidated			Equity Affiliates*			Total
Developed
Consolidated operations
End of 2019			1,048			334			1,382			3			149			94			181			1,809			73			1,882
End of 2020			765			263			1,028			6			129			77			175			1,415			68			1,483
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
Undeveloped
Consolidated operations
End of 2019			183			463			646			2			49			40			16			753			—			753
End of 2020			114			430			544			—			45			31			16			636			—			636
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

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

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Notable changes in proved crude oil reserves in the three years ended December 31, 2022, included:

• 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.

In 2021, Alaska upward revisions were primarily driven by higher prices. Downward revisions in Lower 48 were due to development timing for specific well locations from unconventional plays of 203 million barrels and technical revisions of 35 million barrels, partially offset by upward revisions due to higher prices of 115 million barrels and additional infill drilling in the unconventional plays of 71 million barrels. Upward revisions in Europe were primarily due to higher prices. In Asia Pacific/Middle East, increases were due to higher prices of 21 million barrels and technical revisions of 16 million barrels.

In 2020, Alaska downward revisions were primarily driven by lower prices of 243 million barrels and development plan changes of 54 million barrels. Downward revisions in Lower 48 were due to lower prices of 89 million barrels and development timing for specific well locations from unconventional plays of 82 million barrels, partially offset by upward technical revisions and additional infill drilling in the unconventional plays of 45 million barrels.

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

In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

• Extensions and discoveries: 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.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category.

In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category.

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Years Ended December 31			Natural Gas Liquids
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Total Consolidated			Equity Affiliates*			Total
Developed and Undeveloped
Consolidated operations
End of 2019			100			245			345			2			13			1			361			39			400
Revisions			—			(26)			(26)			—			1			(1)			(26)			—			(26)
Improved recovery			—			—			—			—			—			—			—			—			—
Purchases			—			2			2			2			—			—			4			—			4
Extensions and discoveries			—			41			41			1			—			—			42			—			42
Production			(6)			(27)			(33)			(1)			(2)			—			(36)			(3)			(39)
Sales			—			(5)			(5)			—			—			—			(5)			—			(5)
End of 2020			94			230			324			4			12			—			340			36			376
Revisions			(6)			213			207			—			1			—			208			—			208
Improved recovery			—			—			—			—			—			—			—			—			—
Purchases			—			72			72			—			—			—			72			—			72
Extensions and discoveries			—			82			82			2			—			—			84			—			84
Production			(6)			(50)			(56)			(1)			(2)			—			(59)			(3)			(62)
Sales			—			(1)			(1)			—			—			—			(1)			—			(1)
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

Years Ended December 31			Natural Gas Liquids
Millions of Barrels
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Total Consolidated			Equity Affiliates*			Total
Developed
Consolidated operations
End of 2019			100			99			199			1			10			1			211			39			250
End of 2020			94			83			177			4			9			—			190			36			226
End of 2021			82			334			416			3			9			—			428			33			461
End of 2022			78			409			487			3			10			—			500			31			531
Undeveloped
Consolidated operations
End of 2019			—			146			146			1			3			—			150			—			150
End of 2020			—			147			147			—			3			—			150			—			150
End of 2021			—			212			212			2			2			—			216			—			216
End of 2022			—			340			340			2			3			—			345			19			364

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

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Notable changes in proved NGL reserves in the three years ended December 31, 2022, included:

• Revisions: 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 natural gas liquids) basis adding 70 million barrels, and higher prices of 13 million barrels. This was partially offset by increasing operating costs of 38 million barrels.

In 2021, upward revisions in Lower 48 were due to conversion of acquired Concho Permian two-stream contracts to a three-stream (crude oil, natural gas and natural gas liquids) basis, adding 182 million barrels, additional infill drilling in the unconventional plays of 44 million barrels, technical revisions of 21 million barrels and higher prices of 28 million barrels, partially offset by downward revisions related to development timing for specific well locations from unconventional plays of 62 million barrels.

In 2020, downward revisions in Lower 48 were due to lower prices of 33 million barrels and development timing for specific well locations from unconventional plays of 20 million barrels, partially offset by upward technical revisions and additional infill drilling in the unconventional plays of 27 million barrels.

• Purchases: In 2021, Lower 48 purchases were due to the Shell Permian acquisition.

• Extensions and discoveries: 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.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases in the revisions category.

In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays, which more than offset the decreases in the revisions category.

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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			Equity Affiliates*			Total
Developed and Undeveloped
Consolidated operations
End of 2019			2,688			2,431			5,119			43			896			977			224			7,259			4,421			11,680
Revisions			(607)			(439)			(1,046)			(15)			39			103			2			(917)			(382)			(1,299)
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			74			74			29			—			—			—			103			2			105
Extensions and discoveries			—			304			304			33			2			—			—			339			78			417
Production			(85)			(231)			(316)			(16)			(112)			(171)			(2)			(617)			(395)			(1,012)
Sales			—			(39)			(39)			—			—			(58)			—			(97)			—			(97)
End of 2020			1,996			2,100			4,096			74			825			851			224			6,070			3,724			9,794
Revisions			715			41			756			15			54			60			—			885			247			1,132
Improved recovery			—			—			—			—			—			—			—			—			—			—
Purchases			—			2,438			2,438			—			—			—			—			2,438			—			2,438
Extensions and discoveries			—			822			822			46			2			—			—			870			116			986
Production			(86)			(473)			(559)			(30)			(113)			(147)			(7)			(856)			(390)			(1,246)
Sales			—			(270)			(270)			—			—			—			—			(270)			—			(270)
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

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			Equity Affiliates*			Total
Developed
Consolidated operations
End of 2019			2,601			1,398			3,999			30			697			843			224			5,793			3,898			9,691
End of 2020			1,961			1,051			3,012			74			598			806			224			4,714			3,293			8,007
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
Undeveloped
Consolidated operations
End of 2019			87			1,033			1,120			13			199			134			—			1,466			523			1,989
End of 2020			35			1,049			1,084			—			227			45			—			1,356			431			1,787
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

*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 2,416 BCF, 2,748 BCF and 2,286 BCF, as of December 31, 2022, 2021 and 2020, 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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Notable changes in proved natural gas reserves in the three years ended December 31, 2022, included:

• Revisions: 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 2021, upward revisions in Alaska were due to higher prices of 587 BCF and technical revisions of 128 BCF. In Lower 48, upward revisions of 614 BCF were due to higher prices, additional infill drilling in the unconventional plays of 277 BCF and technical revisions of 60 BCF, partially offset by downward revisions due to development timing for specific well locations from unconventional plays of 498 BCF and conversion of previously acquired Permian two-stream contracted volumes to a three-stream (crude oil, natural gas and natural gas liquids) basis of 412 BCF. Upward revisions in Canada were due to higher prices of 29 BCF, partially offset by downward revisions due to technical revisions of 14 BCF. In Europe, upward revisions were primarily due to higher prices. Upward revisions in our consolidated operations in Asia Pacific/Middle East were due to technical revisions of 76 BCF, partially offset by price revisions of 16 BCF. In our equity affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 124 BCF and technical and cost revisions of 123 BCF.

In 2020, downward revisions in Alaska were primarily due to lower prices. In Lower 48, downward revisions of 372 BCF were due to lower prices and 154 BCF were due to development timing for specific well locations from unconventional plays, partially offset by technical revisions of 87 BCF. Downward revisions in our equity affiliates in Asia Pacific/Middle East were due to lower prices of 426 BCF, partially offset by performance revisions of 44 BCF. Upward revisions in our consolidated operations in Asia Pacific/Middle East were due to technical revisions of 88 BCF and price revisions of 15 BCF.

• Purchases: 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.

In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

In 2020, Canada purchases were due to the acquisition of additional Montney acreage.

• Extensions and discoveries: 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.

In 2021, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category. Extensions and discoveries in Canada were primarily driven by ongoing drilling successes in Montney.

In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the unconventional plays which more than offset the decreases resulting from development plan timing in the revisions category. Extensions and discoveries in Canada were primarily driven by ongoing drilling successes in Montney.

• Sales: 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.

In 2021, Lower 48 sales represent the disposition of noncore assets.

In 2020, Asia Pacific/Middle East sales represent the disposition of the Australia-West assets.

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Years Ended December 31			Bitumen
Millions of Barrels
			Canada			Total Consolidated			Equity Affiliates*			Total
Developed and Undeveloped
Consolidated operations
End of 2019			282			282			—			282
Revisions			(15)			(15)			—			(15)
Improved recovery			—			—			—			—
Purchases			—			—			—			—
Extensions and discoveries			85			85			—			85
Production			(20)			(20)			—			(20)
Sales			—			—			—			—
End of 2020			332			332			—			332
Revisions			(50)			(50)			—			(50)
Improved recovery			—			—			—			—
Purchases			—			—			—			—
Extensions and discoveries			—			—			—			—
Production			(25)			(25)			—			(25)
Sales			—			—			—			—
End of 2021			257			257			—			257
Revisions			(17)			(17)			—			(17)
Improved recovery			—			—			—			—
Purchases			—			—			—			—
Extensions and discoveries			—			—			—			—
Production			(24)			(24)			—			(24)
Sales			—			—			—			—
End of 2022			216			216			—			216

Years Ended December 31			Bitumen
Millions of Barrels
			Canada			Total Consolidated			Equity Affiliates*			Total
Developed
Consolidated operations
End of 2019			187			187			—			187
End of 2020			117			117			—			117
End of 2021			150			150			—			150
End of 2022			127			127			—			127
Undeveloped
Consolidated operations
End of 2019			95			95			—			95
End of 2020			215			215			—			215
End of 2021			107			107			—			107
End of 2022			89			89			—			89

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

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Notable changes in proved bitumen reserves in the three years ended December 31, 2022, included:

• Revisions: 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.

In 2021, downward revisions of 64 million barrels were driven by changes in carbon tax costs and 39 million barrels due to changes in development timing for specific pad locations from the Surmont development program, partially offset by upward revisions from price of 53 million barrels.

In 2020, downward revisions in Canada were due to changes in development timing for specific pad locations from the Surmont development program of 12 million barrels with the remaining revisions primarily related to lower prices.

• Extensions and discoveries: In 2021, extensions and discoveries in Canada were primarily due to planned development to add specific pad locations from the Surmont development program, which more than offset the decrease in the revisions category.

In 2020, extensions and discoveries in Canada were due to planned development to add specific pad locations from the Surmont development program, which offset the decrease in the revisions category of 31 million barrels.

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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			Equity Affiliates*			Total
Developed and Undeveloped
Consolidated operations
End of 2019			1,779			1,447			3,226			296			360			298			234			4,414			848			5,262
Revisions			(398)			(226)			(624)			(20)			12			13			(3)			(622)			(63)			(685)
Improved recovery			—			—			—			—			—			3			—			3			—			3
Purchases			—			19			19			10			—			—			—			29			—			29
Extensions and discoveries			10			200			210			95			—			—			—			305			13			318
Production			(85)			(142)			(227)			(25)			(49)			(55)			(3)			(359)			(73)			(432)
Sales			—			(25)			(25)			(1)			—			(10)			—			(36)			—			(36)
End of 2020			1,306			1,273			2,579			355			323			249			228			3,734			725			4,459
Revisions			322			168			490			(45)			23			47			6			521			42			563
Improved recovery			1			—			1			—			—			—			—			1			—			1
Purchases			—			1,169			1,169			—			—			—			—			1,169			—			1,169
Extensions and discoveries			10			508			518			15			3			1			—			537			19			556
Production			(84)			(289)			(373)			(35)			(50)			(48)			(14)			(520)			(73)			(593)
Sales			—			(54)			(54)			—			—			—			—			(54)			—			(54)
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

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			Equity Affiliates*			Total
Developed
Consolidated operations
End of 2019			1,582			666			2,248			197			275			236			218			3,174			761			3,935
End of 2020			1,186			521			1,707			140			238			211			212			2,508			653			3,161
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
Undeveloped
Consolidated operations
End of 2019			197			781			978			99			85			62			16			1,240			87			1,327
End of 2020			120			752			872			215			85			38			16			1,226			72			1,298
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

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

Natural gas reserves are converted to barrels of oil equivalent (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 2022:

			Proved Undeveloped Reserves
			Millions of Barrels of Oil Equivalent
End of 2021			1,450
Revisions			344
Improved recovery			3
Purchases			33
Extensions and discoveries			627
Sales			(24)
Transfers to Proved Developed			(391)
End of 2022			2,042

Revisions were predominantly driven by changes in development plans in Lower 48.

Extensions and discoveries were largely driven by the addition of 344 MMBOE in Lower 48 for the continued development of unconventional plays. Equity affiliates, primarily in the Middle East, contributed 241 MMBOE. The remaining extensions and discoveries were driven by the continued development planned in the other geographic regions.

Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 82 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 December 31, 2022, our PUDs represented 31 percent of total proved reserves, compared with 24 percent at December 31, 2021. Costs incurred for the year ended December 31, 2022, relating to the development of PUDs were $5.7 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 2022, approximately 93 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 remaining PUDs are in major development areas which are currently producing and predominantly within our Canada and Asia Pacific/Middle East geographic areas.

Results of Operations

The company’s results of operations from oil and gas activities for the years 2022, 2021 and 2020 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.

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Results of Operations

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
Sales			$	7,210		24,309			31,519			1,622			6,594			2,602			1,339			—			43,676
Transfers			6			—			6			—			—			—			—			—			6
Transportation costs			(647)			—			(647)			—			—			—			—			—			(647)
Other revenues			(1)			115			114			338			1			536			184			10			1,183
Total revenues			6,568			24,424			30,992			1,960			6,595			3,138			1,523			10			44,218
Production costs excluding taxes			1,160			3,600			4,760			581			511			342			55			—			6,249
Taxes other than income taxes			1,265			1,687			2,952			21			36			243			2			—			3,254
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
Impairments			2			(11)			(9)			(2)			(1)			—			—			—			(12)
Other related expenses			(19)			4			(15)			(41)			(178)			40			5			6			(183)
Accretion			78			55			133			11			62			25			—			—			231
			3,215			14,057			17,272			887			5,350			1,922			1,406			2			26,839
Income tax provision (benefit)			866			3,113			3,979			198			4,057			512			1,301			53			10,100
Results of operations			$	2,349		10,944			13,293			689			1,293			1,410			105			(51)			16,739
Equity affiliates
Sales			$	—		—			—			—			—			1,000			—			—			1,000
Transfers			—			—			—			—			—			4,272			—			—			4,272
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			41			—			—			41
Total revenues			—			—			—			—			—			5,313			—			—			5,313
Production costs excluding taxes			—			—			—			—			—			491			—			—			491
Taxes other than income taxes			—			—			—			—			—			1,536			—			—			1,536
Exploration expenses			—			—			—			—			—			—			—			—			—
Depreciation, depletion and amortization			—			—			—			—			—			530									530
Impairments			—			—			—			—			—			—			—			—			—
Other related expenses			—			—			—			—			—			(2)			—			—			(2)
Accretion			—			—			—			—			—			27			—			—			27
			—			—			—			—			—			2,731			—			—			2,731
Income tax provision (benefit)			—			—			—			—			—			836			—			—			836
Results of operations			$	—		—			—			—			—			1,895			—			—			1,895

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Year Ended December 31,2021			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
Consolidated operations
Sales			$	4,832		14,093			18,925			1,219			3,568			2,525			917			—			27,154
Transfers			4			—			4			—			—			—			—			—			4
Transportation costs			(626)			—			(626)			—			—			—			—			—			(626)
Other revenues			14			135			149			323			(5)			237			141			(161)			684
Total revenues			4,224			14,228			18,452			1,542			3,563			2,762			1,058			(161)			27,216
Production costs excluding taxes			1,073			2,414			3,487			518			487			466			43			—			5,001
Taxes other than income taxes			442			937			1,379			23			36			91			1			1			1,531
Exploration expenses			80			98			178			39			21			51			2			15			306
Depreciation, depletion and amortization			864			4,053			4,917			383			844			787			35			—			6,966
Impairments			5			(8)			(3)			6			(24)			7			—			—			(14)
Other related expenses			(31)			12			(19)			(22)			(42)			4			4			12			(63)
Accretion			71			47			118			10			70			26			—			—			224
			1,720			6,675			8,395			585			2,171			1,330			973			(189)			13,265
Income tax provision (benefit)			378			1,467			1,845			145			1,673			494			870			(53)			4,974
Results of operations			$	1,342		5,208			6,550			440			498			836			103			(136)			8,291
Equity affiliates
Sales			$	—		—			—			—			—			745			—			—			745
Transfers			—			—			—			—			—			1,797			—			—			1,797
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			5			—			—			5
Total revenues			—			—			—			—			—			2,547			—			—			2,547
Production costs excluding taxes			—			—			—			—			—			329			—			—			329
Taxes other than income taxes			—			—			—			—			—			824			—			—			824
Exploration expenses			—			—			—			—			—			268			—			—			268
Depreciation, depletion and amortization			—			—			—			—			—			593									593
Impairments			—			—			—			—			—			718			—			—			718
Other related expenses			—			—			—			—			—			3			—			—			3
Accretion			—			—			—			—			—			17			—			—			17
			—			—			—			—			—			(205)			—			—			(205)
Income tax provision (benefit)			—			—			—			—			—			(42)			—			—			(42)
Results of operations			$	—		—			—			—			—			(163)			—			—			(163)

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Year Ended December 31,2020			Millions of Dollars
Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
Consolidated operations
Sales			$	2,944		3,421			6,365			230			1,560			1,717			129			—			10,001
Transfers			4			—			4			—			—			191			—			—			195
Transportation costs			(587)			—			(587)			—			—			(19)			—			—			(606)
Other revenues			(1)			(20)			(21)			40			(21)			576			11			10			595
Total revenues			2,360			3,401			5,761			270			1,539			2,465			140			10			10,185
Production costs excluding taxes			1,058			1,399			2,457			366			417			478			21			2			3,741
Taxes other than income taxes			296			263			559			16			30			42			3			1			651
Exploration expenses			1,099			73			1,172			40			52			71			13			108			1,456
Depreciation, depletion and amortization			840			2,544			3,384			335			755			808			8			—			5,290
Impairments			—			804			804			3			5			—			—			—			812
Other related expenses			46			5			51			5			(58)			(25)			(29)			2			(54)
Accretion			72			46			118			8			73			33			—			—			232
			(1,051)			(1,733)			(2,784)			(503)			265			1,058			124			(103)			(1,943)
Income tax provision (benefit)			(271)			(430)			(701)			(191)			116			277			88			(20)			(431)
Results of operations			$	(780)		(1,303)			(2,083)			(312)			149			781			36			(83)			(1,512)
Equity affiliates
Sales			$	—		—			—			—			—			483			—			—			483
Transfers			—			—			—			—			—			1,205			—			—			1,205
Transportation costs			—			—			—			—			—			—			—			—			—
Other revenues			—			—			—			—			—			8			—			—			8
Total revenues			—			—			—			—			—			1,696			—			—			1,696
Production costs excluding taxes			—			—			—			—			—			289			—			—			289
Taxes other than income taxes			—			—			—			—			—			502			—			—			502
Exploration expenses			—			—			—			—			—			20			—			—			20
Depreciation, depletion and amortization			—			—			—			—			—			569									569
Impairments			—			—			—			—			—			—			—			—			—
Other related expenses			—			—			—			—			—			(2)			—			—			(2)
Accretion			—			—			—			—			—			15			—			—			15
			—			—			—			—			—			303			—			—			303
Income tax provision (benefit)			—			—			—			—			—			39			—			—			39
Results of operations			$	—		—			—			—			—			264			—			—			264

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Statistics

Net Production			2022			2021			2020
			Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska			177			178			181
Lower 48			534			447			213
United States			711			625			394
Canada			6			8			6
Europe			71			81			78
Asia Pacific			61			65			69
Africa			36			37			8
Total consolidated operations			885			816			555
Equity affiliates—Asia Pacific/Middle East			13			13			13
Total company			898			829			568
Delaware Basin Area (Lower 48)*			258			162			28
Greater Prudhoe Area (Alaska)*			67			67			68
Natural Gas Liquids
Consolidated operations
Alaska			17			16			16
Lower 48			221			110			74
United States			238			126			90
Canada			3			4			2
Europe			3			4			4
Asia Pacific			—			—			1
Total consolidated operations			244			134			97
Equity affiliates—Asia Pacific/Middle East			8			8			8
Total company			252			142			105
Delaware Basin Area (Lower 48)*			114			27			11
Greater Prudhoe Area (Alaska)*			17			16			15
Bitumen
Consolidated operations—Canada			66			69			55
Total company			66			69			55
Natural Gas			Millions of Cubic Feet Daily
Consolidated operations
Alaska			34			16			10
Lower 48			1,402			1,340			585
United States			1,436			1,356			595
Canada			61			80			40
Europe			306			298			270
Asia Pacific			114			360			429
Africa			22			15			5
Total consolidated operations			1,939			2,109			1,339
Equity affiliates—Asia Pacific/Middle East			1,191			1,053			1,055
Total company			3,130			3,162			2,394
Delaware Basin Area (Lower 48)*			752			584			99
Greater Prudhoe Area (Alaska)*			32			12			4

*At year-end 2022 and 2021, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. At year-end 2021 and 2020, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.

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Average Sales Prices			2022			2021			2020
Crude Oil Per Barrel
Consolidated operations
Alaska*			$	92.58		60.81			33.72
Lower 48			94.46			66.12			35.17
United States			93.96			64.53			34.48
Canada			79.94			56.38			23.57
Europe			99.88			68.94			42.80
Asia Pacific			105.52			70.36			42.84
Africa			97.85			69.06			48.64
Total international			100.75			68.85			42.39
Total consolidated operations			95.27			65.53			36.69
Equity affiliates—Asia Pacific/Middle East			97.31			69.45			39.02
Total operations			95.30			65.59			36.75
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48			$	35.36		30.63			12.13
United States			35.36			30.63			12.13
Canada			37.70			31.18			5.41
Europe			54.52			43.97			23.27
Asia Pacific			—			—			33.21
Total international			46.16			37.50			20.25
Total consolidated operations			35.67			31.04			12.90
Equity affiliates—Asia Pacific/Middle East			61.22			54.16			32.69
Total operations			36.50			32.45			14.61
Bitumen Per Barrel
Consolidated operations—Canada			$	55.56		37.52			8.02 **
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska			$	3.64		2.81			2.91
Lower 48			5.92			4.38			1.65
United States			5.92			4.38			1.66
Canada			3.62			2.54			1.21
Europe			35.33			13.75			3.23
Asia Pacific*			5.84			6.56			5.27
Africa			6.59			3.73			3.71
Total international			23.54			8.91			4.31
Total consolidated operations			10.56			6.00			3.13
Equity affiliates—Asia Pacific/Middle East			9.39			5.31			3.71
Total operations			10.60			5.77			3.38

*Average sales prices for Alaska crude oil and Asia Pacific natural gas above reflect 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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			2022			2021			2020
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska			$	15.89		14.92			14.60
Lower 48			9.97			8.48			9.93
United States			10.97			9.78			11.51
Canada			18.73			15.10			14.29
Europe			11.20			9.88			8.97
Asia Pacific			11.71			10.21			9.26
Africa			3.77			2.95			6.38
Total international			12.36			10.53			10.11
Total consolidated operations			11.27			9.99			10.99
Equity affiliates—Asia Pacific/Middle East			6.14			4.60			4.01
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada			$	17.62		13.41			12.45
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	17.33		6.15			4.08
Lower 48			4.67			3.29			1.87
United States			6.80			3.87			2.62
Canada			0.68			0.67			0.62
Europe			0.79			0.73			0.65
Asia Pacific			8.32			1.99			0.81
Africa			0.14			0.07			0.91
Total international			2.51			1.06			0.72
Total consolidated operations			5.87			3.06			1.91
Equity affiliates—Asia Pacific/Middle East			19.22			11.52			6.96
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska			$	11.41		12.02			11.59
Lower 48			13.42			14.24			18.05
United States			13.08			13.79			15.86
Canada			11.41			11.16			13.08
Europe			15.19			17.13			16.24
Asia Pacific			17.71			17.25			15.66
Africa			2.47			2.40			2.43
Total international			13.28			14.25			15.01
Total consolidated operations			13.12			13.92			15.54
Equity affiliates—Asia Pacific/Middle East			6.63			8.29			7.89

*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, 2022, 2021 and 2020. 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
			2022			2021			2020						2022			2021			2020
Exploratory
Consolidated operations
Alaska			—			—			—						—			1			3
Lower 48			118			87			3						—			—			—
United States			118			87			3						—			1			3
Canada			6			12			23						—			—			—
Europe			—			—			—						2			—			*
Asia Pacific/Middle East			—			*			*						1			*			*
Africa			—			—			—						3			—			*
Other areas			—			—			—						—			—			*
Total consolidated operations			124			99			26						6			1			3
Equity affiliates
Asia Pacific/Middle East			*****			3			8						—			—			—
Total equity affiliates			*****			3			8						—			—			—
Development
Consolidated operations
Alaska			11			1			7						—			—			—
Lower 48			388			339			127						—			—			—
United States			399			340			134						—			—			—
Canada			11			2			—						—			—			—
Europe			3			7			7						—			—			—
Asia Pacific/Middle East			22			21			16						—			—			—
Africa			2			1			2						—			—			—
Other areas			—			—			—						—			—			—
Total consolidated operations			437			371			159						—			—			—
Equity affiliates
Asia Pacific/Middle East			28			30			109						—			—			—
Total equity affiliates			28			30			109						—			—			—

*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, 2022, 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, 2022.

Wells at December 31, 2022

												Productive
			In Progress									Oil									Gas
			Gross			Net						Gross			Net						Gross			Net
Consolidated operations
Alaska			2			1						1,591			929						—			—
Lower 48			615			300						13,512			6,382						3,716			1,767
United States			617			301						15,103			7,311						3,716			1,767
Canada			42			30						192			96						147			147
Europe			22			5						487			84						58			2
Asia Pacific/Middle East			4			2						398			188						6			2
Africa			8			2						869			177						10			2
Other areas			—			—						—			—						—			—
Total consolidated operations			693			340						17,049			7,856						3,937			1,920
Equity affiliates
Asia Pacific/Middle East			279			39						—			—						4,989			1,505
Total equity affiliates			279			39						—			—						4,989			1,505

Acreage at December 31, 2022

			Thousands of Acres
			Developed									Undeveloped
			Gross			Net						Gross			Net
Consolidated operations
Alaska			715			531						1,261			1,246
Lower 48			3,654			2,277						10,279			8,064
United States			4,369			2,808						11,540			9,310
Canada			289			219						3,429			1,944
Europe			430			50						1,195			470
Asia Pacific/Middle East			422			152						10,451			6,930
Africa			358			73						12,545			2,561
Other areas			—			—						156			125
Total consolidated operations			5,868			3,302						39,316			21,340
Equity affiliates
Asia Pacific/Middle East			1,045			314						3,943			1,066
Total equity affiliates			1,045			314						3,943			1,066

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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
2022
Consolidated operations
Unproved property acquisition			$	—		255			255			—			—			—			—			—			255
Proved property acquisition			—			249			249			—			—			—			104			—			353
			—			504			504			—			—			—			104			—			608
Exploration			61			1,278			1,339			99			121			59			3			2			1,623
Development			1,316			4,559			5,875			475			711			425			4			—			7,490
			$	1,377		6,341			7,718			574			832			484			111			2			9,721
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			881			—			—			881
			—			—			—			—			—			881			—			—			881
Exploration			—			—			—			—			—			25			—			—			25
Development			—			—			—			—			—			244			—			—			244
			$	—		—			—			—			—			1,150			—			—			1,150
2021
Consolidated operations
Unproved property acquisition			$	1		11,261			11,262			4			—			—			—			—			11,266
Proved property acquisition			—			16,101			16,101			1			—			—			—			—			16,102
			1			27,362			27,363			5			—			—			—			—			27,368
Exploration			84			765			849			80			31			51			2			40			1,053
Development			949			2,461			3,410			175			398			433			24			—			4,440
			$	1,034		30,588			31,622			260			429			484			26			40			32,861
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			—			—			—			—
			—			—			—			—			—			—			—			—			—
Exploration			—			—			—			—			—			5			—			—			5
Development			—			—			—			—			—			21			—			—			21
			$	—		—			—			—			—			26			—			—			26
2020
Consolidated operations
Unproved property acquisition			$	4		10			14			378			—			3			—			9			404
Proved property acquisition			—			62			62			129			—			—			—			—			191
			4			72			76			507			—			3			—			9			595
Exploration			287			116			403			218			110			32			4			38			805
Development			745			1,758			2,503			102			451			427			18			—			3,501
			$	1,036		1,946			2,982			827			561			462			22			47			4,901
Equity affiliates
Unproved property acquisition			$	—		—			—			—			—			—			—			—			—
Proved property acquisition			—			—			—			—			—			—			—			—			—
			—			—			—			—			—			—			—			—			—
Exploration			—			—			—			—			—			12			—			—			12
Development			—			—			—			—			—			282			—			—			282
			$	—		—			—			—			—			294			—			—			294

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Capitalized Costs

At December 31			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Other Areas			Total
2022
Consolidated operations
Proved property			$	24,041		62,756			86,797			7,487			13,716			10,534			1,075			—			119,609
Unproved property			589			5,145			5,734			1,291			100			93			98			9			7,325
			24,630			67,901			92,531			8,778			13,816			10,627			1,173			9			126,934
Accumulated depreciation, depletion and amortization			11,906			31,455			43,361			2,927			9,774			7,970			458			9			64,499
			$	12,724		36,446			49,170			5,851			4,042			2,657			715			—			62,435
Equity affiliates
Proved property			$	—		—			—			—			—			10,823			—			—			10,823
Unproved property			—			—			—			—			—			2,162			—			—			2,162
			—			—			—			—			—			12,985			—			—			12,985
Accumulated depreciation, depletion and amortization			—			—			—			—			—			8,400			—			—			8,400
			$	—		—			—			—			—			4,585			—			—			4,585
2021
Consolidated operations
Proved property			$	22,750		58,561			81,311			7,380			14,514			12,226			966			—			116,397
Unproved property			1,402			7,704			9,106			1,517			155			92			114			9			10,993
			24,152			66,265			90,417			8,897			14,669			12,318			1,080			9			127,390
Accumulated depreciation, depletion and amortization			11,945			29,975			41,920			2,749			10,166			9,240			422			9			64,506
			$	12,207		36,290			48,497			6,148			4,503			3,078			658			—			62,884
Equity affiliates
Proved property			$	—		—			—			—			—			10,357			—			—			10,357
Unproved property			—			—			—			—			—			2,162			—			—			2,162
			—			—			—			—			—			12,519			—			—			12,519
Accumulated depreciation, depletion and amortization			—			—			—			—			—			8,539			—			—			8,539
			$	—		—			—			—			—			3,980			—			—			3,980

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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
2022
Consolidated operations
Future cash inflows			$	94,332		195,605			289,937			13,768			44,942			13,458			27,067			389,172
Less:
Future production costs			47,979			63,987			111,966			5,722			7,559			5,582			1,085			131,914
Future development costs			8,501			21,379			29,880			960			4,378			1,159			531			36,908
Future income tax provisions			8,882			23,136			32,018			863			25,416			1,780			23,615			83,692
Future net cash flows			28,970			87,103			116,073			6,223			7,589			4,937			1,836			136,658
10 percent annual discount			13,733			31,191			44,924			1,936			1,827			1,505			746			50,938
Discounted future net cash flows			$	15,237		55,912			71,149			4,287			5,762			3,432			1,090			85,720
Equity affiliates
Future cash inflows			$	—		—			—			—			—			87,644			—			87,644
Less:									—
Future production costs			—			—			—			—			—			51,912			—			51,912
Future development costs			—			—			—			—			—			2,685			—			2,685
Future income tax provisions			—			—			—			—			—			8,988			—			8,988
Future net cash flows			—			—			—			—			—			24,059			—			24,059
10 percent annual discount			—			—			—			—			—			10,787			—			10,787
Discounted future net cash flows			$	—		—			—			—			—			13,272			—			13,272
Total company
Discounted future net cash flows			$	15,237		55,912			71,149			4,287			5,762			16,704			1,090			98,992

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			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total
2021
Consolidated operations
Future cash inflows			$	65,910		125,197			191,107			10,847			21,670			11,583			15,778			250,985
Less:
Future production costs			34,444			43,034			77,478			4,960			6,090			4,987			801			94,316
Future development costs			8,033			13,386			21,419			923			3,960			1,314			413			28,029
Future income tax provisions			5,310			13,167			18,477			117			8,345			1,542			13,506			41,987
Future net cash flows			18,123			55,610			73,733			4,847			3,275			3,740			1,058			86,653
10 percent annual discount			7,963			22,290			30,253			1,639			696			930			440			33,958
Discounted future net cash flows			$	10,160		33,320			43,480			3,208			2,579			2,810			618			52,695
Equity affiliates
Future cash inflows			$	—		—			—			—			—			27,851			—			27,851
Less:									—
Future production costs			—			—			—			—			—			15,491			—			15,491
Future development costs			—			—			—			—			—			1,649			—			1,649
Future income tax provisions			—			—			—			—			—			3,071			—			3,071
Future net cash flows			—			—			—			—			—			7,640			—			7,640
10 percent annual discount			—			—			—			—			—			2,640			—			2,640
Discounted future net cash flows			$	—		—			—			—			—			5,000			—			5,000
Total company
Discounted future net cash flows			$	10,160		33,320			43,480			3,208			2,579			7,810			618			57,695

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			Millions of Dollars
			Alaska			Lower 48			Total U.S.			Canada			Europe			Asia Pacific/ Middle East			Africa			Total
2020
Consolidated operations
Future cash inflows			$	30,145		31,533			61,678			4,198			9,857			7,940			9,997			93,670
Less:
Future production costs			22,905			17,582			40,487			4,316			4,770			3,838			1,277			54,688
Future development costs			7,932			12,799			20,731			750			3,688			1,289			461			26,919
Future income tax provisions			—			376			376			—			267			1,075			7,571			9,289
Future net cash flows			(692)			776			84			(868)			1,132			1,738			688			2,774
10 percent annual discount			(1,501)			(820)			(2,321)			(396)			117			406			294			(1,900)
Discounted future net cash flows			$	809		1,596			2,405			(472)			1,015			1,332			394			4,674
Equity affiliates
Future cash inflows			$	—		—			—			—			—			17,284			—			17,284
Less:
Future production costs			—			—			—			—			—			10,239			—			10,239
Future development costs			—			—			—			—			—			1,186			—			1,186
Future income tax provisions			—			—			—			—			—			1,728			—			1,728
Future net cash flows			—			—			—			—			—			4,131			—			4,131
10 percent annual discount			—			—			—			—			—			1,269			—			1,269
Discounted future net cash flows			$	—		—			—			—			—			2,862			—			2,862
Total company
Discounted future net cash flows			$	809		$	1,596		$	2,405		$	(472)		$	1,015		$	4,194		$	394		$	7,536

*Undiscounted future net cash flows related to the proved oil and gas reserves disclosed for Canada for the year ending December 31, 2020, are negative due to the inclusion of asset retirement costs and certain indirect costs in the calculation of the standardized measure of discounted future net cash flows. These costs are not required to be included in the economic limit test for proved developed reserves as defined in Regulation S-X Rule 4-10. Future net cash flows for Canada were also impacted by lower 12-month average pricing for bitumen and crude oil in 2020. Commodity prices have since improved in the current environment.

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Sources of Change in Discounted Future Net Cash Flows

			Millions of Dollars
			Consolidated Operations												Equity Affiliates												Total Company
			2022			2021			2020						2022			2021			2020						2022			2021			2020
Discounted future net cash flows at the beginning of the year			$	52,695		$	4,674		27,372						$	5,000		2,862			7,170						$	57,695		7,536			34,542
Changes during the year
Revenues less production costs for the year			(33,532)			(20,000)			(5,198)						(3,245)			(1,389)			(897)						(36,777)			(21,389)			(6,095)
Net change in prices, and production costs			61,902			50,956			(34,307)						8,184			3,822			(4,769)						70,086			54,778			(39,076)
Extensions, discoveries and improved recovery, less estimated future costs			7,882			10,420			887						1,472			(44)			22						9,354			10,376			909
Development costs for the year			6,687			4,396			3,593						272			91			192						6,959			4,487			3,785
Changes in estimated future development costs			(4,088)			(33)			754						189			(104)			(205)						(3,899)			(137)			549
Purchases of reserves in place, less estimated future costs			3,353			17,833			1						1,282			—			(3)						4,635			17,833			(2)
Sales of reserves in place, less estimated future costs			(3,847)			(468)			(302)						—			—			—						(3,847)			(468)			(302)
Revisions of previous quantity estimates			13,080			2,985			(2,299)						2,193			178			(42)						15,273			3,163			(2,341)
Accretion of discount			7,021			964			3,984						616			344			804						7,637			1,308			4,788
Net change in income taxes			(25,433)			(19,032)			10,189						(2,691)			(760)			590						(28,124)			(19,792)			10,779
Total changes			33,025			48,021			(22,698)						8,272			2,138			(4,308)						41,297			50,159			(27,006)
Discounted future net cash flows at year end			$	85,720		$	52,695		4,674						$	13,272		5,000			2,862						$	98,992		57,695			7,536

• 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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