Cover
Cover - shares | 9 Months Ended | |
Sep. 30, 2023 | Oct. 31, 2023 | |
Cover [Abstract] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2023 | |
Document Transition Report | false | |
Entity File Number | 1-40144 | |
Entity Registrant Name | APA CORPORATION | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 86-1430562 | |
Entity Address, Address Line One | One Post Oak Central, 2000 Post Oak Boulevard, Suite 100 | |
Entity Address, City or Town | Houston | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77056-4400 | |
City Area Code | 713 | |
Local Phone Number | 296-6000 | |
Title of 12(b) Security | Common Stock, $0.625 par value | |
Trading Symbol | APA | |
Security Exchange Name | NASDAQ | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 306,719,421 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2023 | |
Document Fiscal Period Focus | Q3 | |
Entity Central Index Key | 0001841666 | |
Current Fiscal Year End Date | --12-31 |
STATEMENT OF CONSOLIDATED OPERA
STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | ||
REVENUES AND OTHER: | |||||
Derivative instrument gains (losses), net | $ 0 | $ (44) | $ 104 | $ (138) | |
Gain on divestitures, net | 1 | 31 | 7 | 1,180 | |
Other, net | 0 | (2) | 77 | 107 | |
Total revenues and other | 2,309 | 2,872 | 6,300 | 9,752 | |
OPERATING EXPENSES: | |||||
Lease operating expenses | 394 | 364 | 1,076 | 1,067 | |
Taxes other than income | 61 | 82 | 163 | 230 | |
Exploration | 49 | 95 | 144 | 193 | |
General and administrative | 139 | 69 | 276 | 314 | |
Transaction, reorganization, and separation | 5 | 4 | 11 | 21 | |
Depreciation, depletion, and amortization | 418 | 310 | 1,117 | 879 | |
Asset retirement obligation accretion | 29 | 29 | 86 | 87 | |
Impairments | 0 | 0 | 46 | 0 | |
Financing costs, net | 81 | 75 | 235 | 303 | |
Total operating expenses | 1,476 | 1,700 | 3,957 | 4,820 | |
NET INCOME BEFORE INCOME TAXES | 833 | 1,172 | 2,343 | 4,932 | |
Current income tax provision | 422 | 357 | 1,022 | 1,164 | |
Deferred income tax provision (benefit) | (144) | 285 | (22) | 225 | |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | 555 | 530 | 1,343 | 3,543 | |
Net loss attributable to Altus Preferred Unit limited partners | 0 | 0 | 0 | (70) | |
NET INCOME ATTRIBUTABLE TO COMMON STOCK | $ 459 | $ 422 | $ 1,082 | $ 3,231 | |
NET INCOME PER COMMON SHARE: | |||||
Basic (in USD per share) | $ 1.49 | $ 1.28 | $ 3.50 | $ 9.54 | |
Diluted (in USD per share) | $ 1.49 | $ 1.28 | $ 3.50 | $ 9.51 | |
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | |||||
Basic (in shares) | 308 | 329 | 309 | 339 | |
Diluted (in shares) | 308 | 330 | 309 | 340 | |
Noncontrolling interest – Egypt | |||||
OPERATING EXPENSES: | |||||
Net income attributable to noncontrolling interest | $ 96 | $ 108 | $ 261 | $ 368 | |
Noncontrolling interest - Altus | |||||
OPERATING EXPENSES: | |||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | 14 | |
Oil and gas | |||||
REVENUES AND OTHER: | |||||
Total revenues | 2,308 | 2,887 | 6,112 | 8,603 | |
Gathering, processing, and transmission costs | |||||
REVENUES AND OTHER: | |||||
Oil, natural gas, and natural gas liquids production revenues | [1] | 2,079 | 2,302 | 5,500 | 7,147 |
OPERATING EXPENSES: | |||||
Gathering, processing, and transmission & purchased oil and gas costs | [1] | 89 | 99 | 245 | 274 |
Purchased oil and gas sales | |||||
REVENUES AND OTHER: | |||||
Purchased oil and gas sales | [1] | 229 | 585 | 612 | 1,456 |
OPERATING EXPENSES: | |||||
Gathering, processing, and transmission & purchased oil and gas costs | [1] | $ 211 | $ 573 | $ 558 | $ 1,452 |
[1]For transactions associated with Kinetik, refer to Note 6—Equity Method Interests for further detail. |
STATEMENT OF CONSOLIDATED COMPR
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | $ 555 | $ 530 | $ 1,343 | $ 3,543 |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | ||||
Pension and postretirement benefit plan | 0 | 0 | 3 | (1) |
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS | 555 | 530 | 1,346 | 3,542 |
Comprehensive loss attributable to Altus Preferred Unit limited partners | 0 | 0 | 0 | (70) |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK | 459 | 422 | 1,085 | 3,230 |
Noncontrolling interest – Egypt | ||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | ||||
Comprehensive income attributable to noncontrolling interest | 96 | 108 | 261 | 368 |
Noncontrolling interest - Altus | ||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | ||||
Comprehensive income attributable to noncontrolling interest | $ 0 | $ 0 | $ 0 | $ 14 |
STATEMENT OF CONSOLIDATED CASH
STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2023 | Sep. 30, 2022 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income including noncontrolling interests | $ 1,343 | $ 3,543 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Unrealized derivative instrument (gains) losses, net | (61) | 119 |
Gain on divestitures, net | (7) | (1,180) |
Exploratory dry hole expense and unproved leasehold impairments | 91 | 129 |
Depreciation, depletion, and amortization | 1,117 | 879 |
Asset retirement obligation accretion | 86 | 87 |
Impairments | 46 | 0 |
Provision for (benefit from) deferred income taxes | (22) | 225 |
(Gain) loss on extinguishment of debt | (9) | 67 |
Other, net | (45) | (91) |
Changes in operating assets and liabilities: | ||
Receivables | (289) | (554) |
Inventories | 19 | (81) |
Drilling advances and other current assets | 40 | 7 |
Deferred charges and other long-term assets | 227 | (3) |
Accounts payable | (2) | 175 |
Accrued expenses | 1 | 249 |
Deferred credits and noncurrent liabilities | (436) | (41) |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 2,099 | 3,530 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Additions to upstream oil and gas property | (1,747) | (1,168) |
Acquisition of Delaware Basin properties | (24) | (563) |
Leasehold and property acquisitions | (11) | (30) |
Proceeds from sale of oil and gas properties | 29 | 778 |
Proceeds from sale of Kinetik shares | 0 | 224 |
Deconsolidation of Altus cash and cash equivalents | 0 | (143) |
Other, net | (29) | 8 |
NET CASH USED IN INVESTING ACTIVITIES | (1,782) | (894) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Proceeds from (payments on) revolving credit facilities, net | 202 | (22) |
Payments on Apache fixed-rate debt | (65) | (1,370) |
Distributions to noncontrolling interest – Egypt | (154) | (237) |
Treasury stock activity, net | (208) | (884) |
Dividends paid to APA common stockholders | (232) | (127) |
Other, net | (10) | (30) |
NET CASH USED IN FINANCING ACTIVITIES | (467) | (2,670) |
NET DECREASE IN CASH AND CASH EQUIVALENTS | (150) | (34) |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 245 | 302 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 95 | 268 |
SUPPLEMENTARY CASH FLOW DATA: | ||
Interest paid, net of capitalized interest | 278 | 274 |
Income taxes paid, net of refunds | $ 867 | $ 1,029 |
CONSOLIDATED BALANCE SHEET (Una
CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 95 | $ 245 |
Receivables, net of allowance of $103 and $117 | 1,753 | 1,466 |
Other current assets (Note 5) | 952 | 997 |
Total current assets | 2,800 | 2,708 |
PROPERTY AND EQUIPMENT: | ||
Oil and gas properties | 43,908 | 42,356 |
Gathering, processing, and transmission facilities | 447 | 449 |
Other | 613 | 613 |
Less: Accumulated depreciation, depletion, and amortization | (35,468) | (34,406) |
Property and equipment, net | 9,500 | 9,012 |
OTHER ASSETS: | ||
Equity method interests (Note 6) | 681 | 624 |
Decommissioning security for sold Gulf of Mexico properties (Note 11) | 38 | 217 |
Deferred charges and other | 526 | 586 |
Assets | 13,545 | 13,147 |
CURRENT LIABILITIES: | ||
Accounts payable | 741 | 771 |
Current debt | 2 | 2 |
Other current liabilities (Note 7) | 1,892 | 2,143 |
Total current liabilities | 2,635 | 2,916 |
LONG-TERM DEBT (Note 9) | 5,582 | 5,451 |
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: | ||
Income taxes | 305 | 314 |
Asset retirement obligation (Note 8) | 2,006 | 1,940 |
Decommissioning contingency for sold Gulf of Mexico properties (Note 11) | 470 | 738 |
Other | 440 | 443 |
Total deferred credits and other noncurrent liabilities | 3,221 | 3,435 |
EQUITY: | ||
Common stock, $0.625 par, 860,000,000 shares authorized, 420,593,611 and 419,869,987 shares issued, respectively | 263 | 262 |
Paid-in capital | 11,197 | 11,420 |
Accumulated deficit | (4,732) | (5,814) |
Treasury stock, at cost, 113,797,342 and 108,310,838 shares, respectively | (5,667) | (5,459) |
Accumulated other comprehensive income | 17 | 14 |
APA SHAREHOLDERS’ EQUITY | 1,078 | 423 |
TOTAL EQUITY | 2,107 | 1,345 |
TOTAL LIABILITIES AND EQUITY | 13,545 | 13,147 |
Noncontrolling interest – Egypt | ||
EQUITY: | ||
Noncontrolling interest – Egypt | $ 1,029 | $ 922 |
CONSOLIDATED BALANCE SHEET (U_2
CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Receivables, allowance | $ 103 | $ 117 |
Common stock, par value (in USD per share) | $ 0.625 | $ 0.625 |
Common stock, shares authorized (in shares) | 860,000,000 | 860,000,000 |
Common stock, shares issued (in shares) | 420,593,611 | 419,869,987 |
Treasury stock, shares (in shares) | 113,797,342 | 108,310,838 |
STATEMENT OF CONSOLIDATED CHANG
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) - USD ($) $ in Millions | Total | Noncontrolling interest – Egypt | Noncontrolling interest - Altus | APA SHAREHOLDERS’ EQUITY | Common Stock | Paid-In Capital | Accumulated Deficit | Treasury Stock | Accumulated Other Comprehensive Income | Noncontrolling Interests | Noncontrolling Interests Noncontrolling interest – Egypt | Noncontrolling Interests Noncontrolling interest - Altus | [1] | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners | ||||
Beginning balance at Dec. 31, 2021 | [1] | $ 712 | ||||||||||||||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||||||||||||
Net loss attributable to Altus Preferred Unit limited partners | [1] | (70) | ||||||||||||||||
Deconsolidation of Altus | $ (72) | $ (72) | (642) | [1] | ||||||||||||||
Ending balance at Sep. 30, 2022 | [1] | 0 | ||||||||||||||||
Beginning balance at Dec. 31, 2021 | $ (717) | $ (1,595) | $ 262 | $ 11,645 | $ (9,488) | $ (4,036) | $ 22 | $ 878 | [1] | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to common stock | 3,231 | 3,231 | 3,231 | |||||||||||||||
Net income attributable to noncontrolling interest | $ 368 | 14 | $ 368 | [1] | 14 | |||||||||||||
Distributions to noncontrolling interest | (237) | (237) | [1] | |||||||||||||||
Common dividends declared | (165) | (165) | (165) | |||||||||||||||
Deconsolidation of Altus | (72) | $ (72) | (642) | [1] | ||||||||||||||
Treasury stock activity, net | (884) | (884) | (884) | |||||||||||||||
Other | 13 | 13 | 14 | (1) | ||||||||||||||
Ending balance at Sep. 30, 2022 | 1,551 | 600 | 262 | 11,494 | (6,257) | (4,920) | 21 | 951 | [2] | |||||||||
Ending balance at Sep. 30, 2022 | [1] | $ 0 | ||||||||||||||||
Beginning balance at Jun. 30, 2022 | 1,505 | 584 | 262 | 11,567 | (6,679) | (4,587) | 21 | 921 | [2] | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to common stock | 422 | 422 | 422 | |||||||||||||||
Net income attributable to noncontrolling interest | 108 | 0 | 108 | [2] | ||||||||||||||
Distributions to noncontrolling interest | (78) | (78) | [2] | |||||||||||||||
Common dividends declared | (80) | (80) | (80) | |||||||||||||||
Treasury stock activity, net | (333) | (333) | (333) | |||||||||||||||
Other | 7 | 7 | 7 | |||||||||||||||
Ending balance at Sep. 30, 2022 | 1,551 | 600 | 262 | 11,494 | (6,257) | (4,920) | 21 | 951 | [2] | |||||||||
Beginning balance at Dec. 31, 2022 | 1,345 | 423 | 262 | 11,420 | (5,814) | (5,459) | 14 | 922 | [1] | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to common stock | 1,082 | 1,082 | 1,082 | |||||||||||||||
Net income attributable to noncontrolling interest | 261 | 0 | 261 | [1] | ||||||||||||||
Distributions to noncontrolling interest | (154) | (154) | [1] | |||||||||||||||
Common dividends declared | (232) | (232) | (232) | |||||||||||||||
Treasury stock activity, net | (208) | (208) | (208) | |||||||||||||||
Other | 13 | 13 | 1 | 9 | 3 | |||||||||||||
Ending balance at Sep. 30, 2023 | 2,107 | 1,078 | 263 | 11,197 | (4,732) | (5,667) | 17 | 1,029 | [2] | |||||||||
Beginning balance at Jun. 30, 2023 | 1,696 | 709 | 263 | 11,267 | (5,191) | (5,647) | 17 | 987 | [2] | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to common stock | 459 | 459 | 459 | |||||||||||||||
Net income attributable to noncontrolling interest | 96 | $ 0 | 96 | [2] | ||||||||||||||
Distributions to noncontrolling interest | $ (54) | $ (54) | [2] | |||||||||||||||
Common dividends declared | (77) | (77) | (77) | |||||||||||||||
Treasury stock activity, net | (20) | (20) | (20) | |||||||||||||||
Other | 7 | 7 | 7 | |||||||||||||||
Ending balance at Sep. 30, 2023 | $ 2,107 | $ 1,078 | $ 263 | $ 11,197 | $ (4,732) | $ (5,667) | $ 17 | $ 1,029 | [2] | |||||||||
[1]As a result of the BCP Business Combination (as defined herein), the Company deconsolidated Altus (as defined herein) on February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail. Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail. |
STATEMENT OF CONSOLIDATED CHA_2
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) (Parenthetical) - $ / shares | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Jun. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
Statement of Stockholders' Equity [Abstract] | |||||
Common stock, dividends, per share (in USD per share) | $ 0.25 | $ 0.25 | $ 0.125 | $ 0.75 | $ 0.50 |
NATURE OF OPERATIONS
NATURE OF OPERATIONS | 9 Months Ended |
Sep. 30, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS | These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, which contains a summary of the Company’s significant accounting policies and other disclosures. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 9 Months Ended |
Sep. 30, 2023 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES As of September 30, 2023, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail. Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 10—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom. Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). Refer to Note 4—Derivative Instruments and Hedging Activities , Note 6—Equity Method Interests , and Note 9—Debt and Financing Costs for further detail regarding the Company’s fair value measurements recorded on a recurring basis. During the three and nine months ended September 30, 2023 and 2022, the Company recorded no asset impairments in connection with fair value assessments. Revenue Recognition There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment. In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period. Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date. Oil and Gas Property The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost. Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 9 Months Ended |
Sep. 30, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES 2023 Activity During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $1 million and $11 million, respectively. During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions. 2022 Activity During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations. During the third quarter and first nine months of 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $3 million and $30 million, respectively. During the third quarter and first nine months of 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $37 million and $52 million, respectively, recognizing a gain of approximately $34 million and $36 million, respectively, upon closing of these transactions. During the first nine months of 2022, the Company completed a transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million. The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s share of ALTM’s deconsolidated balance sheet of $193 million and the fair value of $802 million of its approximate 20 percent retained ownership in the combined entity. During the first quarter of 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and recognized a loss of $25 million, including transaction fees. Refer to Note 6—Equity Method Interests for further detail. |
CAPITALIZED EXPLORATORY WELL CO
CAPITALIZED EXPLORATORY WELL COSTS | 9 Months Ended |
Sep. 30, 2023 | |
Extractive Industries [Abstract] | |
CAPITALIZED EXPLORATORY WELL COSTS | CAPITALIZED EXPLORATORY WELL COSTS The Company’s capitalized exploratory well costs were $541 million and $474 million as of September 30, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity offshore Suriname and in Egypt. Approximately $5 million of suspended well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the third quarter of 2023. Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects. |
DERIVATIVE INSTRUMENTS AND HEDG
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES | 9 Months Ended |
Sep. 30, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES | DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Objectives and Strategies The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values. Counterparty Risk The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023, the Company had derivative positions with seven counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates. Derivative Instruments Commodity Derivative Instruments As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts: Basis Swap Purchased Basis Swap Sold Production Period Settlement Index MMBtu Weighted Average Price Differential MMBtu Weighted Average Price Differential October—December 2023 NYMEX Henry Hub/IF Waha 18,400 $(1.15) — — October—December 2023 NYMEX Henry Hub/IF HSC — — 18,400 $(0.08) January—June 2024 NYMEX Henry Hub/IF Waha 16,380 $(1.15) — — January—June 2024 NYMEX Henry Hub/IF HSC — — 16,380 $(0.10) Fair Value Measurements The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Quoted Price in Active Markets Significant Other Inputs Significant Unobservable Inputs Total Netting (1) Carrying Amount (In millions) September 30, 2023 Assets: Commodity derivative instruments $ — $ 16 $ — $ 16 $ — $ 16 December 31, 2022 Assets: Commodity derivative instruments $ — $ 5 $ — $ 5 $ — $ 5 Liabilities: Commodity derivative instruments — 50 — 50 — 50 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances. The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement. Derivative Activity Recorded in the Consolidated Balance Sheet All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: September 30, 2023 December 31, 2022 (In millions) Current Assets: Other current assets $ 16 $ — Other Assets: Deferred charges and other — 5 Total derivative assets $ 16 $ 5 Current Liabilities: Other current liabilities $ — $ 50 Total derivative liabilities $ — $ 50 Derivative Activity Recorded in the Statement of Consolidated Operations The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Realized: Commodity derivative instruments $ 19 $ (2) $ 43 $ (11) Foreign currency derivative instruments — (6) — (8) Realized gains (losses), net 19 (8) 43 (19) Unrealized: Commodity derivative instruments (19) (35) 61 (79) Foreign currency derivative instruments — (1) — (9) Preferred Units embedded derivative — — — (31) Unrealized gains (losses), net (19) (36) 61 (119) Derivative instrument gains (losses), net $ — $ (44) $ 104 $ (138) Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.” |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 9 Months Ended |
Sep. 30, 2023 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
OTHER CURRENT ASSETS | OTHER CURRENT ASSETS The following table provides detail of the Company’s other current assets: September 30, 2023 December 31, 2022 (In millions) Inventories $ 443 $ 427 Drilling advances 87 89 Prepaid assets and other 49 31 Current decommissioning security for sold Gulf of Mexico assets 373 450 Total Other current assets $ 952 $ 997 |
EQUITY METHOD INTERESTS
EQUITY METHOD INTERESTS | 9 Months Ended |
Sep. 30, 2023 | |
Equity Method Investments and Joint Ventures [Abstract] | |
EQUITY METHOD INTERESTS | EQUITY METHOD INTERESTS The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations. The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares. The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock. The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49 million in the first nine months of 2023 and 2022, respectively. These gains and losses were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations. The following table represents sales and costs associated with Kinetik: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Natural gas and NGLs sales $ 35 $ — $ 78 $ — Purchased oil and gas sales 11 — 18 — $ 46 $ — $ 96 $ — Gathering, processing, and transmission costs $ 26 $ 28 $ 81 $ 64 Purchased oil and gas costs 37 — 65 — $ 63 $ 28 $ 146 $ 64 As of September 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $43 million and receivables from Kinetik of approximately $29 million. |
OTHER CURRENT LIABILITIES
OTHER CURRENT LIABILITIES | 9 Months Ended |
Sep. 30, 2023 | |
Payables and Accruals [Abstract] | |
OTHER CURRENT LIABILITIES | OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities: September 30, 2023 December 31, 2022 (In millions) Accrued operating expenses $ 161 $ 145 Accrued exploration and development 328 333 Accrued compensation and benefits 379 514 Accrued interest 66 97 Accrued income taxes 228 90 Current asset retirement obligation 55 55 Current operating lease liability 108 167 Current decommissioning contingency for sold Gulf of Mexico properties 225 450 Other 342 292 Total Other current liabilities $ 1,892 $ 2,143 |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 9 Months Ended |
Sep. 30, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATION | ASSET RETIREMENT OBLIGATION The following table describes changes to the Company’s asset retirement obligation (ARO) liability: September 30, 2023 (In millions) Asset retirement obligation, December 31, 2022 $ 1,995 Liabilities incurred 14 Liabilities settled (34) Accretion expense 86 Asset retirement obligation, September 30, 2023 2,061 Less current portion (55) Asset retirement obligation, long-term $ 2,006 |
DEBT AND FINANCING COSTS
DEBT AND FINANCING COSTS | 9 Months Ended |
Sep. 30, 2023 | |
Debt Disclosure [Abstract] | |
DEBT AND FINANCING COSTS | DEBT AND FINANCING COSTS The following table presents the carrying values of the Company’s debt: September 30, 2023 December 31, 2022 (In millions) Apache notes and debentures before unamortized discount and debt issuance costs (1) $ 4,835 $ 4,908 Syndicated credit facilities (2) 768 566 Apache finance lease obligations 33 34 Unamortized discount (26) (27) Debt issuance costs (26) (28) Total debt 5,584 5,453 Current maturities (2) (2) Long-term debt $ 5,582 $ 5,451 (1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively. The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates. At each of September 30, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations. During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility. During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility. On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility). • One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options. • The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options. In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion. As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020. Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023, there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities. Financing Costs, Net The following table presents the components of the Company’s financing costs, net: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Interest expense $ 89 $ 80 $ 266 $ 249 Amortization of debt issuance costs 1 1 3 8 Capitalized interest (7) (5) (18) (13) (Gain) loss on extinguishment of debt — — (9) 67 Interest income (2) (1) (7) (8) Financing costs, net $ 81 $ 75 $ 235 $ 303 |
INCOME TAXES
INCOME TAXES | 9 Months Ended |
Sep. 30, 2023 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXESThe Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur. During the third quarter of 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability. On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023. The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 9 Months Ended |
Sep. 30, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Legal Matters The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2023, the Company has an accrued liability of approximately $49 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity. For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Argentine Environmental Claims On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer. Louisiana Restoration As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims. Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims. Apollo Exploration Lawsuit In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation , Cause No. CV50538 in the 385 th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings. Australian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims. Canadian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al. , No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized by the end of 2023. California and Delaware Litigation On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit. Kulp Minerals Lawsuit On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation , Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit. Shareholder and Derivative Lawsuits On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company intends to vigorously defend this lawsuit. On January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, on February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits. Environmental Matters As of September 30, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million. On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. The Company is not aware of any environmental claims existing as of September 30, 2023, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties. Potential Decommissioning Obligations on Sold Properties In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets. On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets. As of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit. As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.” On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation , Cause No. 2023-38238 in the 281 st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281 st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Apache intends to vigorously defend these claims, and will vigorously pursue its counterclaims. |
CAPITAL STOCK
CAPITAL STOCK | 9 Months Ended |
Sep. 30, 2023 | |
Equity [Abstract] | |
CAPITAL STOCK | CAPITAL STOCK Net Income per Common Share The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements: For the Quarter Ended September 30, 2023 2022 Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 459 308 $ 1.49 $ 422 329 $ 1.28 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — 1 $ — Diluted: Income attributable to common stock $ 459 308 $ 1.49 $ 422 330 $ 1.28 For the Nine Months Ended September 30, 2023 2022 Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 1,082 309 $ 3.50 $ 3,231 339 $ 9.54 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — 1 $ (0.03) Diluted: Income attributable to common stock $ 1,082 309 $ 3.50 $ 3,231 340 $ 9.51 The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.7 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.5 million during the first nine months of 2023 and 2022, respectively. Stock Repurchase Program During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock. In the third quarter of 2023, the Company repurchased approximately 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share, and as of September 30, 2023, the Company had remaining authorization to repurchase up to 47.1 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share. The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares. The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions. Common Stock Dividend For the quarters ended September 30, 2023 and 2022, the Company paid $77 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127 million, respectively, in dividends on its common stock. |
BUSINESS SEGMENT INFORMATION
BUSINESS SEGMENT INFORMATION | 9 Months Ended |
Sep. 30, 2023 | |
Segment Reporting [Abstract] | |
BUSINESS SEGMENT INFORMATION | BUSINESS SEGMENT INFORMATION As of September 30, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below: Egypt (1) North Sea U.S. Altus Midstream Intersegment Total Upstream For the Quarter Ended September 30, 2023 (In millions) Revenues: Oil revenues $ 724 $ 348 $ 633 $ — $ — $ 1,705 Natural gas revenues 81 66 89 — — 236 Natural gas liquids revenues — 5 133 — — 138 Oil, natural gas, and natural gas liquids production revenues 805 419 855 — — 2,079 Purchased oil and gas sales — — 229 — — 229 805 419 1,084 — — 2,308 Operating Expenses: Lease operating expenses 128 102 164 — — 394 Gathering, processing, and transmission 13 15 61 — — 89 Purchased oil and gas costs — — 211 — — 211 Taxes other than income — — 61 — — 61 Exploration 25 9 4 — 11 49 Depreciation, depletion, and amortization 129 90 199 — — 418 Asset retirement obligation accretion — 20 9 — — 29 295 236 709 — 11 1,251 Operating Income (Loss) (2) $ 510 $ 183 $ 375 $ — $ (11) 1,057 Other Income (Expense): Gain on divestitures, net 1 General and administrative (139) Transaction, reorganization, and separation (5) Financing costs, net (81) Income Before Income Taxes $ 833 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Nine Months Ended September 30, 2023 (In millions) Revenues: Oil revenues $ 1,971 $ 865 $ 1,631 $ — $ — $ 4,467 Natural gas revenues 264 165 229 — — 658 Natural gas liquids revenues — 19 356 — — 375 Oil, natural gas, and natural gas liquids production revenues 2,235 1,049 2,216 — — 5,500 Purchased oil and gas sales — — 612 — — 612 2,235 1,049 2,828 — — 6,112 Operating Expenses: Lease operating expenses 346 278 452 — — 1,076 Gathering, processing, and transmission 26 38 181 — — 245 Purchased oil and gas costs — — 558 — — 558 Taxes other than income — — 163 — — 163 Exploration 91 18 10 — 25 144 Depreciation, depletion, and amortization 378 209 530 — — 1,117 Asset retirement obligation accretion — 57 29 — — 86 Impairments — 46 — — — 46 841 646 1,923 — 25 3,435 Operating Income (Loss) (2) $ 1,394 $ 403 $ 905 $ — $ (25) 2,677 Other Income (Expense): Derivative instrument gains, net 104 Gain on divestitures, net 7 Other, net 77 General and administrative (276) Transaction, reorganization, and separation (11) Financing costs, net (235) Income Before Income Taxes $ 2,343 Total Assets (3) $ 3,518 $ 1,665 $ 7,827 $ — $ 535 $ 13,545 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Quarter Ended September 30, 2022 (In millions) Revenues: Oil revenues $ 739 $ 303 $ 630 $ — $ — $ 1,672 Natural gas revenues 84 44 300 — — 428 Natural gas liquids revenues — 5 197 — — 202 Oil, natural gas, and natural gas liquids production revenues 823 352 1,127 — — 2,302 Purchased oil and gas sales — — 585 — — 585 823 352 1,712 — — 2,887 Operating Expenses: Lease operating expenses 119 107 138 — — 364 Gathering, processing, and transmission 5 7 87 — — 99 Purchased oil and gas costs — — 573 — — 573 Taxes other than income — — 82 — — 82 Exploration 29 1 16 — 49 95 Depreciation, depletion, and amortization 97 52 161 — — 310 Asset retirement obligation accretion — 21 8 — — 29 250 188 1,065 — 49 1,552 Operating Income (Loss) (2) $ 573 $ 164 $ 647 $ — $ (49) 1,335 Other Income (Expense): Derivative instrument losses, net (44) Gain on divestitures, net 31 Other, net (2) General and administrative (69) Transaction, reorganization, and separation (4) Financing costs, net (75) Income Before Income Taxes $ 1,172 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Nine Months Ended September 30, 2022 (In millions) Revenues: Oil revenues $ 2,431 $ 938 $ 1,883 $ — $ — $ 5,252 Natural gas revenues 270 207 764 — — 1,241 Natural gas liquids revenues 6 33 618 — (3) 654 Oil, natural gas, and natural gas liquids production revenues 2,707 1,178 3,265 — (3) 7,147 Purchased oil and gas sales — — 1,451 5 — 1,456 Midstream service affiliate revenues — — — 16 (16) — 2,707 1,178 4,716 21 (19) 8,603 Operating Expenses: Lease operating expenses 381 321 366 — (1) 1,067 Gathering, processing, and transmission 15 31 241 5 (18) 274 Purchased oil and gas costs — — 1,452 — — 1,452 Taxes other than income — — 227 3 — 230 Exploration 56 8 21 — 108 193 Depreciation, depletion, and amortization 285 168 424 2 — 879 Asset retirement obligation accretion — 61 25 1 — 87 737 589 2,756 11 89 4,182 Operating Income (Loss) (2) $ 1,970 $ 589 $ 1,960 $ 10 $ (108) 4,421 Other Income (Expense): Derivative instrument losses, net (138) Gain on divestitures, net 1,180 Other, net 107 General and administrative (314) Transaction, reorganization, and separation (21) Financing costs, net (303) Income Before Income Taxes $ 4,932 Total Assets (3) $ 3,242 $ 2,185 $ 7,675 $ — $ 527 $ 13,629 (1) Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Oil $ 202 $ 227 $ 539 $ 779 Natural gas 23 26 73 87 Natural gas liquids — — — 2 (2) Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. (3) Intercompany balances are excluded from total assets. (4) Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation. |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Sep. 30, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 9 Months Ended |
Sep. 30, 2023 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. |
Use of Estimates | Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 10—Income Taxes ), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom. |
Fair Value Measurements | Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). |
Revenue Recognition | Revenue Recognition There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment. |
Inventories | Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. |
Property and Equipment | Property and Equipment |
Oil and Gas Property | Oil and Gas Property The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost. Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. |
Gathering, Processing, and Transmission (GPT) Facilities | Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. |
DERIVATIVE INSTRUMENTS AND HE_2
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Positions | As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts: Basis Swap Purchased Basis Swap Sold Production Period Settlement Index MMBtu Weighted Average Price Differential MMBtu Weighted Average Price Differential October—December 2023 NYMEX Henry Hub/IF Waha 18,400 $(1.15) — — October—December 2023 NYMEX Henry Hub/IF HSC — — 18,400 $(0.08) January—June 2024 NYMEX Henry Hub/IF Waha 16,380 $(1.15) — — January—June 2024 NYMEX Henry Hub/IF HSC — — 16,380 $(0.10) |
Schedule of Derivative Assets Measured at Fair Value | The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Quoted Price in Active Markets Significant Other Inputs Significant Unobservable Inputs Total Netting (1) Carrying Amount (In millions) September 30, 2023 Assets: Commodity derivative instruments $ — $ 16 $ — $ 16 $ — $ 16 December 31, 2022 Assets: Commodity derivative instruments $ — $ 5 $ — $ 5 $ — $ 5 Liabilities: Commodity derivative instruments — 50 — 50 — 50 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances. |
Schedule of Derivative Liabilities Measured at Fair Value | The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Quoted Price in Active Markets Significant Other Inputs Significant Unobservable Inputs Total Netting (1) Carrying Amount (In millions) September 30, 2023 Assets: Commodity derivative instruments $ — $ 16 $ — $ 16 $ — $ 16 December 31, 2022 Assets: Commodity derivative instruments $ — $ 5 $ — $ 5 $ — $ 5 Liabilities: Commodity derivative instruments — 50 — 50 — 50 (1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances. |
Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations | The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: September 30, 2023 December 31, 2022 (In millions) Current Assets: Other current assets $ 16 $ — Other Assets: Deferred charges and other — 5 Total derivative assets $ 16 $ 5 Current Liabilities: Other current liabilities $ — $ 50 Total derivative liabilities $ — $ 50 Derivative Activity Recorded in the Statement of Consolidated Operations The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Realized: Commodity derivative instruments $ 19 $ (2) $ 43 $ (11) Foreign currency derivative instruments — (6) — (8) Realized gains (losses), net 19 (8) 43 (19) Unrealized: Commodity derivative instruments (19) (35) 61 (79) Foreign currency derivative instruments — (1) — (9) Preferred Units embedded derivative — — — (31) Unrealized gains (losses), net (19) (36) 61 (119) Derivative instrument gains (losses), net $ — $ (44) $ 104 $ (138) |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of Other Current Assets | The following table provides detail of the Company’s other current assets: September 30, 2023 December 31, 2022 (In millions) Inventories $ 443 $ 427 Drilling advances 87 89 Prepaid assets and other 49 31 Current decommissioning security for sold Gulf of Mexico assets 373 450 Total Other current assets $ 952 $ 997 |
EQUITY METHOD INTERESTS (Tables
EQUITY METHOD INTERESTS (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Schedule of Equity Method Investment Information | The following table represents sales and costs associated with Kinetik: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Natural gas and NGLs sales $ 35 $ — $ 78 $ — Purchased oil and gas sales 11 — 18 — $ 46 $ — $ 96 $ — Gathering, processing, and transmission costs $ 26 $ 28 $ 81 $ 64 Purchased oil and gas costs 37 — 65 — $ 63 $ 28 $ 146 $ 64 |
OTHER CURRENT LIABILITIES (Tabl
OTHER CURRENT LIABILITIES (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Payables and Accruals [Abstract] | |
Schedule of Other Current Liabilities | The following table provides detail of the Company’s other current liabilities: September 30, 2023 December 31, 2022 (In millions) Accrued operating expenses $ 161 $ 145 Accrued exploration and development 328 333 Accrued compensation and benefits 379 514 Accrued interest 66 97 Accrued income taxes 228 90 Current asset retirement obligation 55 55 Current operating lease liability 108 167 Current decommissioning contingency for sold Gulf of Mexico properties 225 450 Other 342 292 Total Other current liabilities $ 1,892 $ 2,143 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligation | The following table describes changes to the Company’s asset retirement obligation (ARO) liability: September 30, 2023 (In millions) Asset retirement obligation, December 31, 2022 $ 1,995 Liabilities incurred 14 Liabilities settled (34) Accretion expense 86 Asset retirement obligation, September 30, 2023 2,061 Less current portion (55) Asset retirement obligation, long-term $ 2,006 |
DEBT AND FINANCING COSTS (Table
DEBT AND FINANCING COSTS (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The following table presents the carrying values of the Company’s debt: September 30, 2023 December 31, 2022 (In millions) Apache notes and debentures before unamortized discount and debt issuance costs (1) $ 4,835 $ 4,908 Syndicated credit facilities (2) 768 566 Apache finance lease obligations 33 34 Unamortized discount (26) (27) Debt issuance costs (26) (28) Total debt 5,584 5,453 Current maturities (2) (2) Long-term debt $ 5,582 $ 5,451 (1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively. The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates. |
Schedule of Financing Costs, Net | The following table presents the components of the Company’s financing costs, net: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Interest expense $ 89 $ 80 $ 266 $ 249 Amortization of debt issuance costs 1 1 3 8 Capitalized interest (7) (5) (18) (13) (Gain) loss on extinguishment of debt — — (9) 67 Interest income (2) (1) (7) (8) Financing costs, net $ 81 $ 75 $ 235 $ 303 |
CAPITAL STOCK (Tables)
CAPITAL STOCK (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Equity [Abstract] | |
Schedule Reconciliation of the Components of Basic and Diluted Net Income Per Common Share | The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements: For the Quarter Ended September 30, 2023 2022 Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 459 308 $ 1.49 $ 422 329 $ 1.28 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — 1 $ — Diluted: Income attributable to common stock $ 459 308 $ 1.49 $ 422 330 $ 1.28 For the Nine Months Ended September 30, 2023 2022 Income Shares Per Share Income Shares Per Share (In millions, except per share amounts) Basic: Income attributable to common stock $ 1,082 309 $ 3.50 $ 3,231 339 $ 9.54 Effect of Dilutive Securities: Stock options and other $ — — $ — $ — 1 $ (0.03) Diluted: Income attributable to common stock $ 1,082 309 $ 3.50 $ 3,231 340 $ 9.51 |
BUSINESS SEGMENT INFORMATION (T
BUSINESS SEGMENT INFORMATION (Tables) | 9 Months Ended |
Sep. 30, 2023 | |
Segment Reporting [Abstract] | |
Schedule of Financial Segment Information | Financial information for each segment is presented below: Egypt (1) North Sea U.S. Altus Midstream Intersegment Total Upstream For the Quarter Ended September 30, 2023 (In millions) Revenues: Oil revenues $ 724 $ 348 $ 633 $ — $ — $ 1,705 Natural gas revenues 81 66 89 — — 236 Natural gas liquids revenues — 5 133 — — 138 Oil, natural gas, and natural gas liquids production revenues 805 419 855 — — 2,079 Purchased oil and gas sales — — 229 — — 229 805 419 1,084 — — 2,308 Operating Expenses: Lease operating expenses 128 102 164 — — 394 Gathering, processing, and transmission 13 15 61 — — 89 Purchased oil and gas costs — — 211 — — 211 Taxes other than income — — 61 — — 61 Exploration 25 9 4 — 11 49 Depreciation, depletion, and amortization 129 90 199 — — 418 Asset retirement obligation accretion — 20 9 — — 29 295 236 709 — 11 1,251 Operating Income (Loss) (2) $ 510 $ 183 $ 375 $ — $ (11) 1,057 Other Income (Expense): Gain on divestitures, net 1 General and administrative (139) Transaction, reorganization, and separation (5) Financing costs, net (81) Income Before Income Taxes $ 833 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Nine Months Ended September 30, 2023 (In millions) Revenues: Oil revenues $ 1,971 $ 865 $ 1,631 $ — $ — $ 4,467 Natural gas revenues 264 165 229 — — 658 Natural gas liquids revenues — 19 356 — — 375 Oil, natural gas, and natural gas liquids production revenues 2,235 1,049 2,216 — — 5,500 Purchased oil and gas sales — — 612 — — 612 2,235 1,049 2,828 — — 6,112 Operating Expenses: Lease operating expenses 346 278 452 — — 1,076 Gathering, processing, and transmission 26 38 181 — — 245 Purchased oil and gas costs — — 558 — — 558 Taxes other than income — — 163 — — 163 Exploration 91 18 10 — 25 144 Depreciation, depletion, and amortization 378 209 530 — — 1,117 Asset retirement obligation accretion — 57 29 — — 86 Impairments — 46 — — — 46 841 646 1,923 — 25 3,435 Operating Income (Loss) (2) $ 1,394 $ 403 $ 905 $ — $ (25) 2,677 Other Income (Expense): Derivative instrument gains, net 104 Gain on divestitures, net 7 Other, net 77 General and administrative (276) Transaction, reorganization, and separation (11) Financing costs, net (235) Income Before Income Taxes $ 2,343 Total Assets (3) $ 3,518 $ 1,665 $ 7,827 $ — $ 535 $ 13,545 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Quarter Ended September 30, 2022 (In millions) Revenues: Oil revenues $ 739 $ 303 $ 630 $ — $ — $ 1,672 Natural gas revenues 84 44 300 — — 428 Natural gas liquids revenues — 5 197 — — 202 Oil, natural gas, and natural gas liquids production revenues 823 352 1,127 — — 2,302 Purchased oil and gas sales — — 585 — — 585 823 352 1,712 — — 2,887 Operating Expenses: Lease operating expenses 119 107 138 — — 364 Gathering, processing, and transmission 5 7 87 — — 99 Purchased oil and gas costs — — 573 — — 573 Taxes other than income — — 82 — — 82 Exploration 29 1 16 — 49 95 Depreciation, depletion, and amortization 97 52 161 — — 310 Asset retirement obligation accretion — 21 8 — — 29 250 188 1,065 — 49 1,552 Operating Income (Loss) (2) $ 573 $ 164 $ 647 $ — $ (49) 1,335 Other Income (Expense): Derivative instrument losses, net (44) Gain on divestitures, net 31 Other, net (2) General and administrative (69) Transaction, reorganization, and separation (4) Financing costs, net (75) Income Before Income Taxes $ 1,172 Egypt (1) North Sea U.S. Altus Midstream Intersegment Total (4) Upstream For the Nine Months Ended September 30, 2022 (In millions) Revenues: Oil revenues $ 2,431 $ 938 $ 1,883 $ — $ — $ 5,252 Natural gas revenues 270 207 764 — — 1,241 Natural gas liquids revenues 6 33 618 — (3) 654 Oil, natural gas, and natural gas liquids production revenues 2,707 1,178 3,265 — (3) 7,147 Purchased oil and gas sales — — 1,451 5 — 1,456 Midstream service affiliate revenues — — — 16 (16) — 2,707 1,178 4,716 21 (19) 8,603 Operating Expenses: Lease operating expenses 381 321 366 — (1) 1,067 Gathering, processing, and transmission 15 31 241 5 (18) 274 Purchased oil and gas costs — — 1,452 — — 1,452 Taxes other than income — — 227 3 — 230 Exploration 56 8 21 — 108 193 Depreciation, depletion, and amortization 285 168 424 2 — 879 Asset retirement obligation accretion — 61 25 1 — 87 737 589 2,756 11 89 4,182 Operating Income (Loss) (2) $ 1,970 $ 589 $ 1,960 $ 10 $ (108) 4,421 Other Income (Expense): Derivative instrument losses, net (138) Gain on divestitures, net 1,180 Other, net 107 General and administrative (314) Transaction, reorganization, and separation (21) Financing costs, net (303) Income Before Income Taxes $ 4,932 Total Assets (3) $ 3,242 $ 2,185 $ 7,675 $ — $ 527 $ 13,629 (1) Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of: For the Quarter Ended September 30, For the Nine Months Ended September 30, 2023 2022 2023 2022 (In millions) Oil $ 202 $ 227 $ 539 $ 779 Natural gas 23 26 73 87 Natural gas liquids — — — 2 (2) Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. (3) Intercompany balances are excluded from total assets. (4) Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation. |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2023 | Jun. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Dec. 31, 2022 | |
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Other asset impairments | $ 0 | $ 0 | $ 0 | $ 0 | ||
Receivables from contracts with customer, net | $ 1,600,000,000 | $ 1,600,000,000 | $ 1,300,000,000 | |||
Inventory write-down | $ 46,000,000 | |||||
Kinetik | ||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Ownership percentage by noncontrolling owners | 10% | 10% | ||||
Sinopec | Apache Egypt | ||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Ownership percentage by noncontrolling owners | 33.33% | 33.33% | ||||
Third-Party Investors | ALTM | ||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Ownership percentage by noncontrolling owners | 21% | 21% |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Feb. 22, 2022 | Mar. 31, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Dec. 31, 2022 | Feb. 21, 2022 | |
Business Acquisition [Line Items] | ||||||||
Proceeds from sale of oil and gas properties | $ 29 | $ 778 | ||||||
Acquisition of delaware basin properties | 24 | 563 | ||||||
Deconsolidation gain | $ 609 | |||||||
Deconsolidation, net amount of balance sheet | 193 | |||||||
Equity method interests | $ 681 | $ 681 | $ 624 | |||||
Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Equity method interests | $ 802 | |||||||
Shares sold (in shares) | 4 | |||||||
Proceeds from sale of stock | $ 224 | |||||||
Loss on disposition of stock | $ 25 | |||||||
Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage by noncontrolling owners | 10% | 10% | ||||||
Apache Midstream LLC | ALTM | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage by parent | 79% | |||||||
BCP Business Combination | ALTM | ALTM | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage by noncontrolling owners | 20% | |||||||
BCP Business Combination | ALTM | Class C Common Stock | ||||||||
Business Acquisition [Line Items] | ||||||||
Business acquisition, equity interest issued or issuable, number of shares (in shares) | 50 | |||||||
BCP Business Combination | BCP Business Combination Contributor | Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage by parent | 75% | |||||||
Non-Core Assets And Leasehold | Disposed of by Sale | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from sale of oil and gas properties | $ 1 | $ 37 | $ 29 | 52 | ||||
Gain on sale of non-core assets | 1 | 34 | 7 | 36 | ||||
Non-Core Mineral Rights | Disposed of by Sale | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from sale of oil and gas properties | 726 | |||||||
Gain on sale of non-core assets | 560 | |||||||
Permian Basin | ||||||||
Business Acquisition [Line Items] | ||||||||
Oil and gas property acquisitions consideration payment | $ 1 | $ 11 | ||||||
Payments to acquire leasehold and property | 3 | 30 | ||||||
Delaware Basin | ||||||||
Business Acquisition [Line Items] | ||||||||
Oil and gas property acquisitions consideration payment | 615 | |||||||
Asset acquisition, proved properties amount | 581 | 581 | ||||||
Asset acquisition, unproved leasehold amount | 38 | 38 | ||||||
Asset acquisition, abandonment obligations | $ 4 | $ 4 |
CAPITALIZED EXPLORATORY WELL _2
CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Extractive Industries [Abstract] | ||
Capitalized exploratory well costs | $ 541 | $ 474 |
Exploratory well costs capitalized for a period greater than one year | $ 5 |
DERIVATIVE INSTRUMENTS AND HE_3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details) | 9 Months Ended |
Sep. 30, 2023 counterparty | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Number of derivative counterparties | 7 |
DERIVATIVE INSTRUMENTS AND HE_4
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Open natural Gas Financial Basis Swap Contracts (Details) - Natural gas revenues MMBTU in Thousands | 9 Months Ended |
Sep. 30, 2023 $ / MMBTU MMBTU | |
Basis Swap Purchased | October—December 2023 | NYMEX Henry Hub/IF Waha | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU | 18,400 |
Weighted average price differential (in USD per MMBtu ) | $ / MMBTU | (1.15) |
Basis Swap Purchased | January—June 2024 | NYMEX Henry Hub/IF Waha | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU | 16,380 |
Weighted average price differential (in USD per MMBtu ) | $ / MMBTU | (1.15) |
Basis Swap Sold | October—December 2023 | NYMEX Henry Hub/IF HSC | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU | 18,400 |
Weighted average price differential (in USD per MMBtu ) | $ / MMBTU | (0.08) |
Basis Swap Sold | January—June 2024 | NYMEX Henry Hub/IF HSC | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU | 16,380 |
Weighted average price differential (in USD per MMBtu ) | $ / MMBTU | (0.10) |
DERIVATIVE INSTRUMENTS AND HE_5
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Assets: | ||
Derivative asset | $ 16 | $ 5 |
Liabilities: | ||
Derivative liability | 0 | 50 |
Commodity derivative instruments | ||
Assets: | ||
Derivative asset, fair value | 16 | 5 |
Derivative asset, netting | 0 | 0 |
Derivative asset | 16 | 5 |
Liabilities: | ||
Derivative liability, fair value | 50 | |
Derivative liability, netting | 0 | |
Derivative liability | 50 | |
Quoted Price in Active Markets (Level 1) | Commodity derivative instruments | ||
Assets: | ||
Derivative asset, fair value | 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | 0 | |
Significant Other Inputs (Level 2) | Commodity derivative instruments | ||
Assets: | ||
Derivative asset, fair value | 16 | 5 |
Liabilities: | ||
Derivative liability, fair value | 50 | |
Significant Unobservable Inputs (Level 3) | Commodity derivative instruments | ||
Assets: | ||
Derivative asset, fair value | $ 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | $ 0 |
DERIVATIVE INSTRUMENTS AND HE_6
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Statement of Financial Position [Extensible Enumeration] | Other Liabilities, Current | Other Liabilities, Current |
Recurring | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset | $ 16 | $ 5 |
Derivative liability | 0 | 50 |
Recurring | Current Assets: Other current assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset | 16 | 0 |
Recurring | Other Assets: Deferred charges and other | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset | $ 0 | $ 5 |
DERIVATIVE INSTRUMENTS AND HE_7
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gains (losses), net | $ 61 | $ (119) | ||
Derivative instrument gains (losses), net | $ 0 | $ (44) | 104 | (138) |
Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gains (losses), net | 19 | (8) | 43 | (19) |
Unrealized gains (losses), net | (19) | (36) | 61 | (119) |
Derivative instrument gains (losses), net | 0 | (44) | 104 | (138) |
Commodity derivative instruments | Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gains (losses), net | 19 | (2) | 43 | (11) |
Unrealized gains (losses), net | (19) | (35) | 61 | (79) |
Foreign currency derivative instruments | Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gains (losses), net | 0 | (6) | 0 | (8) |
Unrealized gains (losses), net | 0 | (1) | 0 | (9) |
Preferred Units embedded derivative | Not Designated as Hedging Instrument | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gains (losses), net | $ 0 | $ 0 | $ 0 | $ (31) |
OTHER CURRENT ASSETS (Details)
OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Inventories | $ 443 | $ 427 |
Drilling advances | 87 | 89 |
Prepaid assets and other | 49 | 31 |
Current decommissioning security for sold Gulf of Mexico assets | 373 | 450 |
Total Other current assets | $ 952 | $ 997 |
EQUITY METHOD INTERESTS - Narra
EQUITY METHOD INTERESTS - Narrative (Details) shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Mar. 31, 2022 USD ($) shares | Sep. 30, 2023 USD ($) shares | Sep. 30, 2022 USD ($) | Jun. 30, 2022 shares | Sep. 30, 2023 USD ($) shares | Sep. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) | Feb. 22, 2022 shares | |
Schedule of Equity Method Investments [Line Items] | ||||||||
Accounts payable | $ 741 | $ 741 | $ 771 | |||||
Receivables | $ 1,753 | $ 1,753 | $ 1,466 | |||||
Kinetik | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Equity method investment, number of shares (in shares) | shares | 20.2 | 17.7 | 20.2 | 12.9 | ||||
Shares sold (in shares) | shares | 4 | |||||||
Loss on sale of stock | $ 25 | |||||||
Dividends paid-in-kind (in shares) | shares | 2.5 | |||||||
Interest percentage | 14% | 14% | ||||||
Gains (losses) on changes in fair value of equity method interest | $ (14) | $ (17) | $ 57 | $ 49 | ||||
Accounts payable | 43 | 43 | ||||||
Receivables | $ 29 | $ 29 | ||||||
Kinetik | Kinetik | ||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||
Stock split conversion ratio | 2 |
EQUITY METHOD INTERESTS - Sales
EQUITY METHOD INTERESTS - Sales and Costs Associated with Equity Method Interest (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | ||
Kinetik | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Sales | $ 46 | $ 0 | $ 96 | $ 0 | |
Costs | 63 | 28 | 146 | 64 | |
Natural gas and NGLs sales | Kinetik | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Sales | 35 | 0 | 78 | 0 | |
Gathering, processing, and transmission costs | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Costs | [1] | 89 | 99 | 245 | 274 |
Gathering, processing, and transmission costs | Kinetik | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Costs | 26 | 28 | 81 | 64 | |
Purchased oil and gas sales | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Costs | [1] | 211 | 573 | 558 | 1,452 |
Purchased oil and gas sales | Kinetik | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Sales | 11 | 0 | 18 | 0 | |
Costs | $ 37 | $ 0 | $ 65 | $ 0 | |
[1]For transactions associated with Kinetik, refer to Note 6—Equity Method Interests for further detail. |
OTHER CURRENT LIABILITIES (Deta
OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Payables and Accruals [Abstract] | ||
Accrued operating expenses | $ 161 | $ 145 |
Accrued exploration and development | 328 | 333 |
Accrued compensation and benefits | 379 | 514 |
Accrued interest | 66 | 97 |
Accrued income taxes | 228 | 90 |
Current asset retirement obligation | 55 | 55 |
Current operating lease liability | 108 | 167 |
Current decommissioning contingency for sold Gulf of Mexico properties | 225 | 450 |
Other | 342 | 292 |
Total Other current liabilities | $ 1,892 | $ 2,143 |
ASSET RETIREMENT OBLIGATION (De
ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Dec. 31, 2022 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||||
Asset retirement obligation at the beginning of period | $ 1,995 | ||||
Liabilities incurred | 14 | ||||
Liabilities settled | (34) | ||||
Accretion expense | $ 29 | $ 29 | 86 | $ 87 | |
Asset retirement obligation at the end of period | 2,061 | 2,061 | |||
Less current portion | (55) | (55) | $ (55) | ||
Asset retirement obligation, long-term | $ 2,006 | $ 2,006 | $ 1,940 |
DEBT AND FINANCING COSTS - Sche
DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions | Sep. 30, 2023 | Dec. 31, 2022 |
Debt Instrument [Line Items] | ||
Apache finance lease obligations | $ 33 | $ 34 |
Unamortized discount | (26) | (27) |
Debt issuance costs | (26) | (28) |
Total debt | 5,584 | 5,453 |
Current maturities | (2) | (2) |
Long-term debt | 5,582 | 5,451 |
Apache notes and debentures | Unsecured Debt | ||
Debt Instrument [Line Items] | ||
Apache notes and debentures before unamortized discount and debt issuance costs | 4,835 | 4,908 |
Debt instrument, fair value | 4,100 | 4,200 |
Syndicated credit facility | Line of Credit | Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Syndicated credit facilities | $ 768 | $ 566 |
DEBT AND FINANCING COSTS - Addi
DEBT AND FINANCING COSTS - Additional Information (Details) £ in Millions | 3 Months Ended | 9 Months Ended | |||||||||
Apr. 29, 2022 USD ($) credit_agreement option | Jan. 18, 2022 USD ($) | Sep. 30, 2023 USD ($) | Sep. 30, 2022 USD ($) | Mar. 31, 2022 USD ($) | Sep. 30, 2023 USD ($) | Sep. 30, 2022 USD ($) | Sep. 30, 2023 GBP (£) | Dec. 31, 2022 USD ($) | Dec. 31, 2022 GBP (£) | Apr. 29, 2022 GBP (£) credit_agreement | |
Debt Instrument [Line Items] | |||||||||||
Finance lease obligations, current | $ 2,000,000 | $ 2,000,000 | $ 2,000,000 | ||||||||
Gain (loss) on extinguishment of debt | 0 | $ 0 | 9,000,000 | $ (67,000,000) | |||||||
Number of syndicated credit agreements | credit_agreement | 2 | 2 | |||||||||
USD Agreement | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument term | 5 years | ||||||||||
Line of credit facility, committed amount | $ 1,800,000,000 | ||||||||||
Line of credit facility, increased committed amount | $ 2,300,000,000 | ||||||||||
Line of credit facility, number of extension options | option | 2 | ||||||||||
Debt extension term | 1 year | ||||||||||
USD Agreement | Line of Credit | Letter of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility maximum borrowing capacity | $ 750,000,000 | ||||||||||
Line of credit facility, current borrowing capacity | 150,000,000 | ||||||||||
Principal amount outstanding | $ 300,000,000 | ||||||||||
Letters of credit outstanding, amount | 0 | 0 | 20,000,000 | ||||||||
GBP Agreement | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt instrument term | 5 years | ||||||||||
Line of credit facility, committed amount | £ | £ 1,500 | ||||||||||
Line of credit facility, number of extension options | option | 2 | ||||||||||
Debt extension term | 1 year | ||||||||||
GBP Agreement | Line of Credit | Letter of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Letters of credit outstanding, amount | £ | £ 572 | £ 652 | |||||||||
Former Facility | Revolving Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Line of credit facility, terminated Amount | $ 4,000,000,000 | ||||||||||
Line of credit facility, covenant benchmark amount | $ 1,000,000,000 | ||||||||||
Syndicated credit facility | Line of Credit | Revolving Credit Facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility | 768,000,000 | 768,000,000 | 566,000,000 | ||||||||
Apache credit facility | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Letters of credit outstanding, amount | 3,000,000 | 3,000,000 | £ 185 | $ 17,000,000 | £ 199 | ||||||
Uncommitted Lines Of Credit | Line of Credit | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Credit facility | 0 | 0 | |||||||||
Senior Notes | 3.25% notes due 2022 | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Current maturities | $ 213,000,000 | ||||||||||
Debt interest rate | 3.25% | ||||||||||
Redemption price, percentage of principal amount redeemed | 100% | ||||||||||
Senior Notes | Open Market Repurchase | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt repurchased principal amount | 74,000,000 | 15,000,000 | 74,000,000 | 15,000,000 | |||||||
Debt instrument repurchase program | $ 65,000,000 | 16,000,000 | 65,000,000 | 16,000,000 | |||||||
Premium (discount) to par of debt repurchase | $ 1,000,000 | (10,000,000) | |||||||||
Gain (loss) on extinguishment of debt | $ (1,000,000) | $ 9,000,000 | |||||||||
Senior Notes | Cash Tender Offers | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt repurchased principal amount | 1,100,000,000 | 1,100,000,000 | |||||||||
Debt instrument repurchase program | 1,200,000,000 | 1,200,000,000 | |||||||||
Gain (loss) on extinguishment of debt | (66,000,000) | ||||||||||
Debt instrument, unamortized discount and issuance costs | $ 11,000,000 | $ 11,000,000 |
DEBT AND FINANCING COSTS - Comp
DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
Debt Disclosure [Abstract] | ||||
Interest expense | $ 89 | $ 80 | $ 266 | $ 249 |
Amortization of debt issuance costs | 1 | 1 | 3 | 8 |
Capitalized interest | (7) | (5) | (18) | (13) |
(Gain) loss on extinguishment of debt | 0 | 0 | (9) | 67 |
Interest income | (2) | (1) | (7) | (8) |
Financing costs, net | $ 81 | $ 75 | $ 235 | $ 303 |
INCOME TAXES (Details)
INCOME TAXES (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2023 USD ($) | |
Foreign Tax Authority | |
Deferred Tax Expense [Line Items] | |
Deferred tax expense, remeasurement of deferred tax liability | $ 174 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Details) $ in Millions | 9 Months Ended | 12 Months Ended | ||||||||||||
Sep. 10, 2020 defendant | Sep. 11, 2019 USD ($) plaintiff | Dec. 20, 2017 action | Jul. 17, 2017 defendant action | Mar. 21, 2016 USD ($) | Mar. 20, 2016 USD ($) | Sep. 30, 2023 USD ($) bond letter_of_credit | Dec. 31, 2013 USD ($) profit_interest | Jun. 21, 2023 surety | Dec. 31, 2022 USD ($) | Apr. 05, 2022 letter | Dec. 31, 2017 AUD ($) | Apr. 30, 2017 AUD ($) | Mar. 12, 2014 USD ($) | |
Commitment And Contingencies [Line Items] | ||||||||||||||
Accrued liability for legal contingencies | $ 49,000,000 | |||||||||||||
Environmental tax and royalty obligations | $ 100,000,000 | |||||||||||||
Retain right of obligations | 45,000,000 | |||||||||||||
Undiscounted reserve for environmental remediation | 5,000,000 | |||||||||||||
Number of prior letters notifying unable to fund decommissioning obligations | letter | 2 | |||||||||||||
Decommissioning costs incurred | 692,000,000 | |||||||||||||
Decommissioning costs reimbursed amount from trust | 288,000,000 | |||||||||||||
Decommissioning costs reimbursed amount from the letters of credit | 87,000,000 | |||||||||||||
Standby loan agreed to provide related to ARO (up to) | 400,000,000 | |||||||||||||
Decommissioning contingency for sold | 695,000,000 | |||||||||||||
Decommissioning contingency for sold properties | 470,000,000 | $ 738,000,000 | ||||||||||||
Current decommissioning contingency for sold Gulf of Mexico properties | 225,000,000 | 450,000,000 | ||||||||||||
Decommissioning security for sold properties | 411,000,000 | |||||||||||||
Trust account for disposal group, number of net profits interests | 38,000,000 | 217,000,000 | ||||||||||||
Current decommissioning security for sold Gulf of Mexico assets | $ 373,000,000 | $ 450,000,000 | ||||||||||||
Sureties issued bonds directly | surety | 2 | |||||||||||||
Sureties issued bonds to issuing bank | surety | 2 | |||||||||||||
Gulf Of Mexico Shelf Operations and Properties | Disposed of by Sale | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Proceeds from sale of operations and properties | $ 3,750,000,000 | |||||||||||||
Trust account for disposal group, number of net profits interests | profit_interest | 2 | |||||||||||||
Number of bond held | bond | 2 | |||||||||||||
Number of debt instrument held | letter_of_credit | 5 | |||||||||||||
Minimum | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
AROs, estimated liability | $ 695,000,000 | |||||||||||||
Maximum | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
AROs, estimated liability | 895,000,000 | |||||||||||||
Apollo Exploration Lawsuit | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Plaintiffs alleged damages | $ 200,000,000 | |||||||||||||
Apollo Exploration Lawsuit | Minimum | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Plaintiffs alleged damages | $ 1,100,000,000 | |||||||||||||
Australian Operations Divestiture Dispute | Apache Australia Operation | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Gain contingency, unrecorded amount | $ 80 | |||||||||||||
Loss contingency, estimated of possible loss amount | $ 200 | |||||||||||||
Canadian Operations Divestiture Dispute | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Plaintiffs alleged damages | $ 60,000,000 | |||||||||||||
Number of plaintiffs | plaintiff | 4 | |||||||||||||
Litigation settlement, amount to resolve all claims | $ 7,000,000 | |||||||||||||
California Litigation | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Number of actions filed | action | 2 | 3 | ||||||||||||
Number of defendants | defendant | 30 | |||||||||||||
Delaware Litigation | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Number of defendants | defendant | 25 |
CAPITAL STOCK - Net Income Per
CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
Basic: | ||||
Income attributable to common stock | $ 459 | $ 422 | $ 1,082 | $ 3,231 |
Income attributable to common stock (in shares) | 308 | 329 | 309 | 339 |
Income attributable to common stock (in USD per share) | $ 1.49 | $ 1.28 | $ 3.50 | $ 9.54 |
Diluted: | ||||
Income attributable to common stock | $ 459 | $ 422 | $ 1,082 | $ 3,231 |
Income attributable to common stock (in shares) | 308 | 330 | 309 | 340 |
Income attributable to common stock (in USD per share) | $ 1.49 | $ 1.28 | $ 3.50 | $ 9.51 |
Stock options and other | ||||
Effect of Dilutive Securities: | ||||
Stock options and other | $ 0 | $ 0 | $ 0 | $ 0 |
Stock options and other, shares (in shares) | 0 | 1 | 0 | 1 |
Stock options and other, per share (in USD per share) | $ 0 | $ 0 | $ 0 | $ (0.03) |
CAPITAL STOCK - Additional Info
CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Oct. 31, 2023 | Sep. 30, 2023 | Sep. 30, 2022 | Jun. 30, 2022 | Dec. 31, 2021 | Sep. 30, 2023 | Sep. 30, 2022 | Dec. 31, 2018 | |
Class of Stock [Line Items] | ||||||||
Options and restricted stock, anti-dilutive (in shares) | 1,700,000 | 2,100,000 | 2,000,000 | 2,500,000 | ||||
Number of shares authorized to be repurchased (in shares) | 40,000,000 | |||||||
Additional number of shares authorized to be repurchased (in shares) | 40,000,000 | 40,000,000 | ||||||
Treasury shares acquired (in shares) | 500,000 | 9,800,000 | 5,500,000 | 24,000,000 | ||||
Treasure stock acquired, average price (in USD per share) | $ 41.90 | $ 33.86 | $ 37.91 | $ 36.78 | ||||
Remaining authorized repurchase amount (in shares) | 47,100,000 | 47,100,000 | ||||||
Payments of dividend on common stock | $ 77 | $ 41 | $ 232 | $ 127 | ||||
Common stock, dividends, per share (in USD per share) | $ 0.25 | $ 0.25 | $ 0.125 | $ 0.75 | $ 0.50 | |||
Subsequent Event | ||||||||
Class of Stock [Line Items] | ||||||||
Treasury shares acquired (in shares) | 400,000 | |||||||
Treasure stock acquired, average price (in USD per share) | $ 40.26 | |||||||
Remaining authorized repurchase amount (in shares) | 46,700,000 |
BUSINESS SEGMENT INFORMATION -
BUSINESS SEGMENT INFORMATION - Additional Information (Details) | 9 Months Ended |
Sep. 30, 2023 segment | |
Segment Reporting [Abstract] | |
Number of operating segments | 3 |
BUSINESS SEGMENT INFORMATION _2
BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Dec. 31, 2022 | ||
Operating Expenses: | ||||||
Lease operating expenses | $ 394 | $ 364 | $ 1,076 | $ 1,067 | ||
Taxes other than income | 61 | 82 | 163 | 230 | ||
Exploration | 49 | 95 | 144 | 193 | ||
Depreciation, depletion, and amortization | 418 | 310 | 1,117 | 879 | ||
Asset retirement obligation accretion | 29 | 29 | 86 | 87 | ||
Impairments | 0 | 0 | 46 | 0 | ||
Total operating expenses | 1,251 | 1,552 | 3,435 | 4,182 | ||
Operating Income (Loss) | 1,057 | 1,335 | 2,677 | 4,421 | ||
Other Income (Expense): | ||||||
Derivative instrument gains (losses), net | 0 | (44) | 104 | (138) | ||
Gain on divestitures, net | 1 | 31 | 7 | 1,180 | ||
Other, net | (2) | 77 | 107 | |||
General and administrative | (139) | (69) | (276) | (314) | ||
Transaction, reorganization, and separation | (5) | (4) | (11) | (21) | ||
Financing costs, net | (81) | (75) | (235) | (303) | ||
NET INCOME BEFORE INCOME TAXES | 833 | 1,172 | 2,343 | 4,932 | ||
Total assets | 13,545 | 13,629 | 13,545 | 13,629 | $ 13,147 | |
Operating Segments | Egypt | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 128 | 119 | 346 | 381 | ||
Taxes other than income | 0 | 0 | 0 | 0 | ||
Exploration | 25 | 29 | 91 | 56 | ||
Depreciation, depletion, and amortization | 129 | 97 | 378 | 285 | ||
Asset retirement obligation accretion | 0 | 0 | 0 | 0 | ||
Impairments | 0 | |||||
Total operating expenses | 295 | 250 | 841 | 737 | ||
Operating Income (Loss) | 510 | 573 | 1,394 | 1,970 | ||
Other Income (Expense): | ||||||
Total assets | 3,518 | 3,242 | 3,518 | 3,242 | ||
Impairments | 1 | 3 | ||||
Operating Segments | North Sea | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 102 | 107 | 278 | 321 | ||
Taxes other than income | 0 | 0 | 0 | 0 | ||
Exploration | 9 | 1 | 18 | 8 | ||
Depreciation, depletion, and amortization | 90 | 52 | 209 | 168 | ||
Asset retirement obligation accretion | 20 | 21 | 57 | 61 | ||
Impairments | 46 | |||||
Total operating expenses | 236 | 188 | 646 | 589 | ||
Operating Income (Loss) | 183 | 164 | 403 | 589 | ||
Other Income (Expense): | ||||||
Total assets | 1,665 | 2,185 | 1,665 | 2,185 | ||
Impairments | 6 | 12 | ||||
Operating Segments | U.S. | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 164 | 138 | 452 | 366 | ||
Taxes other than income | 61 | 82 | 163 | 227 | ||
Exploration | 4 | 16 | 10 | 21 | ||
Depreciation, depletion, and amortization | 199 | 161 | 530 | 424 | ||
Asset retirement obligation accretion | 9 | 8 | 29 | 25 | ||
Impairments | 0 | |||||
Total operating expenses | 709 | 1,065 | 1,923 | 2,756 | ||
Operating Income (Loss) | 375 | 647 | 905 | 1,960 | ||
Other Income (Expense): | ||||||
Total assets | 7,827 | 7,675 | 7,827 | 7,675 | ||
Impairments | 2 | 15 | 7 | 19 | ||
Operating Segments | Suriname | ||||||
Other Income (Expense): | ||||||
Impairments | 1 | 1 | ||||
Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 16 | |||||
Operating Expenses: | ||||||
Lease operating expenses | 0 | 0 | 0 | 0 | ||
Taxes other than income | 0 | 0 | 0 | 3 | ||
Exploration | 0 | 0 | 0 | 0 | ||
Depreciation, depletion, and amortization | 0 | 0 | 0 | 2 | ||
Asset retirement obligation accretion | 0 | 0 | 0 | 1 | ||
Impairments | 0 | |||||
Total operating expenses | 0 | 0 | 0 | 11 | ||
Operating Income (Loss) | 0 | 0 | 0 | 10 | ||
Other Income (Expense): | ||||||
Total assets | 0 | 0 | 0 | 0 | ||
Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | (16) | |||||
Operating Expenses: | ||||||
Lease operating expenses | 0 | 0 | 0 | (1) | ||
Taxes other than income | 0 | 0 | 0 | 0 | ||
Exploration | 11 | 49 | 25 | 108 | ||
Depreciation, depletion, and amortization | 0 | 0 | 0 | 0 | ||
Asset retirement obligation accretion | 0 | 0 | 0 | 0 | ||
Impairments | 0 | |||||
Total operating expenses | 11 | 49 | 25 | 89 | ||
Operating Income (Loss) | (11) | (49) | (25) | (108) | ||
Other Income (Expense): | ||||||
Total assets | 535 | 527 | 535 | 527 | ||
Gathering, processing, and transmission costs | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | [1] | 2,079 | 2,302 | 5,500 | 7,147 | |
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | [1] | 89 | 99 | 245 | 274 | |
Gathering, processing, and transmission costs | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 805 | 823 | 2,235 | 2,707 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 13 | 5 | 26 | 15 | ||
Gathering, processing, and transmission costs | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 419 | 352 | 1,049 | 1,178 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 15 | 7 | 38 | 31 | ||
Gathering, processing, and transmission costs | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 855 | 1,127 | 2,216 | 3,265 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 61 | 87 | 181 | 241 | ||
Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | 5 | ||
Gathering, processing, and transmission costs | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | (3) | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | (18) | ||
Purchased oil and gas sales | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | [1] | 229 | 585 | 612 | 1,456 | |
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | [1] | 211 | 573 | 558 | 1,452 | |
Purchased oil and gas sales | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 0 | 0 | 0 | 0 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | 0 | ||
Purchased oil and gas sales | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 0 | 0 | 0 | 0 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | 0 | ||
Purchased oil and gas sales | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 229 | 585 | 612 | 1,451 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 211 | 573 | 558 | 1,452 | ||
Purchased oil and gas sales | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 0 | 0 | 0 | 5 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | 0 | ||
Purchased oil and gas sales | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Purchased oil and gas sales | 0 | 0 | 0 | 0 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission & purchased oil and gas costs | 0 | 0 | 0 | 0 | ||
Oil and gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 2,308 | 2,887 | 6,112 | 8,603 | ||
Oil and gas | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 805 | 823 | 2,235 | 2,707 | ||
Oil and gas | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 419 | 352 | 1,049 | 1,178 | ||
Oil and gas | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1,084 | 1,712 | 2,828 | 4,716 | ||
Oil and gas | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 0 | 0 | 0 | 21 | ||
Oil and gas | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 0 | 0 | 0 | (19) | ||
Oil revenues | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 202 | 227 | 539 | 779 | ||
Oil revenues | Gathering, processing, and transmission costs | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 1,705 | 1,672 | 4,467 | 5,252 | ||
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 724 | 739 | 1,971 | 2,431 | ||
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 348 | 303 | 865 | 938 | ||
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 633 | 630 | 1,631 | 1,883 | ||
Oil revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Oil revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Natural gas revenues | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 23 | 26 | 73 | 87 | ||
Natural gas revenues | Gathering, processing, and transmission costs | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 236 | 428 | 658 | 1,241 | ||
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 81 | 84 | 264 | 270 | ||
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 66 | 44 | 165 | 207 | ||
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 89 | 300 | 229 | 764 | ||
Natural gas revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Natural gas revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Natural gas liquids revenues | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 0 | 0 | 0 | 2 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 138 | 202 | 375 | 654 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 6 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 5 | 5 | 19 | 33 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 133 | 197 | 356 | 618 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | 0 | ||
Natural gas liquids revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | $ 0 | $ 0 | $ 0 | $ (3) | ||
[1]For transactions associated with Kinetik, refer to Note 6—Equity Method Interests for further detail. |