Cover
Cover - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Jun. 30, 2022 | Jan. 31, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 1-4300 | ||
Entity Registrant Name | APACHE CORPORATION | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 41-0747868 | ||
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 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 1,000 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Entity Central Index Key | 0000006769 | ||
Entity Public Float | $ 0 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Name | Ernst & Young LLP |
Auditor Location | Houston, Texas |
Auditor Firm ID | 42 |
STATEMENT OF CONSOLIDATED OPERA
STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
REVENUES AND OTHER: | ||||
Derivative instrument gains (losses), net | $ (107) | $ 94 | $ (223) | |
Gain on divestitures, net | 1,180 | 67 | 32 | |
Losses on previously sold Gulf of Mexico properties | (157) | (446) | 0 | |
Other, net | 139 | 228 | 64 | |
Total revenues and other | 11,938 | 7,928 | 4,308 | |
OPERATING EXPENSES: | ||||
Lease operating expenses | 1,435 | 1,241 | 1,127 | |
Taxes other than income | 256 | 204 | 123 | |
Exploration | 146 | 127 | 274 | |
General and administrative | 462 | 357 | 290 | |
Transaction, reorganization, and separation | 26 | 22 | 54 | |
Depreciation, depletion, and amortization | 1,177 | 1,360 | 1,772 | |
Asset retirement obligation accretion | 117 | 113 | 109 | |
Impairments | 0 | 208 | 4,501 | |
Financing costs, net | 313 | 472 | 267 | |
Total operating expenses | 6,064 | 5,948 | 9,148 | |
NET INCOME (LOSS) BEFORE INCOME TAXES | 5,874 | 1,980 | (4,840) | |
Current income tax provision | 1,507 | 652 | 176 | |
Deferred income tax provision (benefit) | 145 | (74) | (112) | |
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | 4,222 | 1,402 | (4,904) | |
Net income (loss) attributable to Altus Preferred Unit limited partners | (70) | 162 | 76 | |
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION | 3,536 | 1,062 | (4,860) | |
Noncontrolling Interest, Sinopec | ||||
OPERATING EXPENSES: | ||||
Net income (loss) attributable to noncontrolling interest | 464 | 174 | (121) | |
Noncontrolling Interest, Altus | ||||
OPERATING EXPENSES: | ||||
Net income (loss) attributable to noncontrolling interest | 14 | 4 | 1 | |
Noncontrolling Interest, APA Corporation | ||||
OPERATING EXPENSES: | ||||
Net income (loss) attributable to noncontrolling interest | 278 | 0 | 0 | |
Oil and gas, excluding purchased | ||||
REVENUES AND OTHER: | ||||
Oil, natural gas, and natural gas liquids production revenues | [1] | 9,028 | 6,498 | 4,037 |
OPERATING EXPENSES: | ||||
Cost of oil and gas purchased | [1] | 356 | 264 | 274 |
Oil and gas, purchased | ||||
REVENUES AND OTHER: | ||||
Purchased oil and gas sales | 1,855 | 1,487 | 398 | |
OPERATING EXPENSES: | ||||
Cost of oil and gas purchased | 1,776 | 1,580 | 357 | |
Oil and gas | ||||
REVENUES AND OTHER: | ||||
Total revenues | $ 10,883 | $ 7,985 | $ 4,435 | |
[1] (1) For revenues and gathering, processing, and transmission costs associated with Kinetik, refer to Note 7—Equity Method Interest for further detail. |
STATEMENT OF CONSOLIDATED COMPR
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | $ 4,222 | $ 1,402 | $ (4,904) |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | |||
Pension and postretirement benefit plan | (8) | 7 | (2) |
Share of equity method interests other comprehensive income | 0 | 1 | 0 |
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | 4,214 | 1,410 | (4,906) |
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners | (70) | 162 | 76 |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION | 3,528 | 1,070 | (4,862) |
Noncontrolling Interest, Sinopec | |||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | |||
Comprehensive income (loss), net of tax, attributable to nonredeemable noncontrolling interest | 464 | 174 | (121) |
Net income (loss) attributable to noncontrolling interest | 464 | 174 | (121) |
Noncontrolling Interest, Altus | |||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | |||
Comprehensive income (loss), net of tax, attributable to nonredeemable noncontrolling interest | 14 | 4 | 1 |
Net income (loss) attributable to noncontrolling interest | 14 | 4 | 1 |
Noncontrolling Interest, APA Corporation | |||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | |||
Net income (loss) attributable to noncontrolling interest | $ 278 | $ 0 | $ 0 |
STATEMENT OF CONSOLIDATED CASH
STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) including noncontrolling interests | $ 4,222 | $ 1,402 | $ (4,904) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Unrealized derivative instrument losses (gains), net | 23 | (69) | 87 |
Gain on divestitures, net | (1,180) | (67) | (32) |
Exploratory dry hole expense and unproved leasehold impairments | 92 | 86 | 211 |
Depreciation, depletion, and amortization | 1,177 | 1,360 | 1,772 |
Asset retirement obligation accretion | 117 | 113 | 109 |
Impairments | 0 | 208 | 4,501 |
Provision for (benefit from) deferred income taxes | 145 | (74) | (112) |
Loss (gain) from extinguishment of debt | 67 | 104 | (160) |
Losses on previously sold Gulf of Mexico properties | 157 | 446 | 0 |
Other | (137) | (23) | 102 |
Changes in operating assets and liabilities: | |||
Receivables | (55) | (393) | 149 |
Inventories | (1) | (9) | 19 |
Drilling advances and other current assets | (12) | 60 | (29) |
Deferred charges and other long-term assets | 70 | (42) | (13) |
Accounts payable | 12 | 205 | (167) |
Receivable/payable with APA Corporation | 0 | 40 | 0 |
Accrued expenses | 293 | 127 | (163) |
Deferred credits and noncurrent liabilities | (138) | 31 | 18 |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 4,852 | 3,505 | 1,388 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Additions to upstream oil and gas property | (1,503) | (934) | (1,270) |
Leasehold and property acquisitions | (37) | (9) | (4) |
Noncurrent receivable from APA Corporation | (832) | 0 | 0 |
Contributions to Altus equity method interests | 0 | (28) | (327) |
Proceeds from asset divestitures | 778 | 256 | 166 |
Proceeds from sale of Kinetik shares | 224 | 0 | 0 |
Deconsolidation of Altus cash and cash equivalents | (143) | 0 | 0 |
Other, net | 28 | 49 | (31) |
NET CASH USED IN INVESTING ACTIVITIES | (1,485) | (666) | (1,466) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from Apache credit facility, net | 138 | 392 | 150 |
Proceeds from Altus credit facility | 0 | 33 | 228 |
Proceeds from (payments on) note payable to APA Corporation, net | (835) | 78 | 0 |
Fixed rate debt borrowings | 0 | 0 | 1,238 |
Payments on fixed-rate debt | (1,493) | (1,795) | (1,243) |
Distributions to noncontrolling interest - Sinopec | (362) | (279) | (91) |
Distributions to Altus Preferred Unit limited partners | (11) | (46) | (23) |
Distributions to APA Corporation | (894) | (1,182) | 0 |
Dividends paid | 0 | (9) | (123) |
Other, net | (4) | (14) | (43) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | (3,461) | (2,822) | 93 |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (94) | 17 | 15 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 279 | 262 | 247 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 185 | 279 | 262 |
SUPPLEMENTARY CASH FLOW DATA: | |||
Interest paid, net of capitalized interest | 322 | 442 | 419 |
Income taxes paid, net of refunds | 1,431 | 633 | 212 |
Non-cash financing adjustment: APA’s assumption of Apache’s borrowings on its syndicated credit facility | $ 680 | $ 0 | $ 0 |
CONSOLIDATED BALANCE SHEET
CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |||
CURRENT ASSETS: | |||||
Cash and cash equivalents ($132 related to Altus VIE) | [1] | $ 185 | $ 279 | ||
Receivables, net of allowance of $117 and $109 | [1] | 1,424 | 1,390 | ||
Other current assets (Note 6) ($9 related to Altus VIE) | [1] | 993 | 649 | ||
Accounts receivable from APA Corporation | 0 | 77 | [1] | ||
Total current assets | [1] | 2,602 | 2,395 | ||
PROPERTY AND EQUIPMENT: | |||||
Oil and gas, on the basis of successful efforts accounting: | [1] | 41,245 | 40,474 | ||
Gathering, processing, and transmission facilities ($209 related to Altus VIE) | [1] | 449 | 673 | ||
Other ($3 related to Altus VIE) | [1] | 613 | 1,126 | ||
Less: Accumulated depreciation, depletion, and amortization ($25 related to Altus VIE) | [1] | (34,350) | (34,213) | ||
Property and equipment, net | [1] | 7,957 | 8,060 | ||
OTHER ASSETS: | |||||
Equity method interests (Note 7) ($1,365 related to Altus VIE) | [1] | 624 | 1,365 | ||
Decommissioning security for sold Gulf of Mexico properties (Note 12) | [1] | 217 | 640 | ||
Deferred charges and other ($6 related to Altus VIE) | [1] | 571 | 581 | ||
Noncurrent receivable from APA Corporation | 869 | [1] | 0 | ||
Note receivable from APA Corporation (Note 2) | [1] | 1,415 | 1,352 | ||
Assets | [1] | 14,255 | 14,393 | ||
CURRENT LIABILITIES: | |||||
Accounts payable ($12 related to Altus VIE) | [1] | 646 | 651 | ||
Note payable to APA Corporation (Note 2) | [1] | 0 | 195 | ||
Current debt | [1] | 2 | 215 | ||
Other current liabilities (Note 8) ($15 related to Altus VIE) | [1] | 2,049 | 1,170 | ||
Total current liabilities | [1] | 2,697 | 2,231 | ||
LONG-TERM DEBT (Note 10) ($657 related to Altus VIE) | [1] | 4,885 | 7,295 | ||
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: | |||||
Income taxes | [1] | 314 | 148 | ||
Asset retirement obligation ($68 related to Altus VIE) | [1] | 1,936 | 2,089 | ||
Decommissioning contingency for sold Gulf of Mexico properties (Note 12) | [1] | 738 | 1,086 | ||
Other ($67 related to Altus VIE) | [1] | 443 | 572 | ||
Total deferred credits and other noncurrent liabilities | [1] | 3,431 | 3,895 | ||
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 14) | [1] | 0 | 712 | ||
EQUITY (DEFICIT): | |||||
Common stock, $0.625 par, 1,000 and 1,000 shares authorized, respectively, 1,000 and 1,000 shares issued, respectively | [1] | 0 | 0 | ||
Paid-in capital | [1] | 8,025 | 8,677 | ||
Accumulated deficit | [1] | (5,781) | (9,317) | ||
Accumulated other comprehensive income | [1] | 14 | 22 | ||
EQUITY (DEFICIT) ATTRIBUTABLE TO APA CORPORATION | [1] | 2,258 | (618) | ||
TOTAL EQUITY | [1] | 3,242 | 260 | ||
Liabilities and Equity, Total | [1] | 14,255 | 14,393 | ||
Noncontrolling Interest, Sinopec | |||||
EQUITY (DEFICIT): | |||||
Noncontrolling interest | [1] | 922 | 820 | ||
Noncontrolling Interest, APA Corporation | |||||
EQUITY (DEFICIT): | |||||
Noncontrolling interest | [1] | 62 | 0 | ||
Noncontrolling Interest, Altus | |||||
EQUITY (DEFICIT): | |||||
Noncontrolling interest | [1] | $ 0 | $ 58 | ||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
CONSOLIDATED BALANCE SHEET (Par
CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash and cash equivalent | [1] | $ 185 | $ 279 |
Accounts receivable, after allowance for credit loss, current | [1] | 1,424 | 1,390 |
Other assets, current | [1] | 993 | 649 |
Gathering, processing and transmission facilities | [1] | 449 | 673 |
Other property and equipment | [1] | 613 | 1,126 |
Accumulated depreciation, depletion, and amortization | [1] | 34,350 | 34,213 |
Equity method interests | [1] | 624 | 1,365 |
Deferred charges and other | [1] | 571 | 581 |
Accounts payable | [1] | 646 | 651 |
Other current liabilities | [1] | 2,049 | 1,170 |
Long-term debt | 4,885 | 7,295 | |
Asset retirement obligation | [1] | 1,936 | 2,089 |
Other noncurrent liabilities | [1] | $ 443 | $ 572 |
Common stock, par value (in USD per share) | $ 0.625 | $ 0.625 | |
Common stock, shares authorized (in shares) | 1,000 | 1,000 | |
Common stock, shares issued (in shares) | 1,000 | 1,000 | |
Variable Interest Entity, Primary Beneficiary | |||
Cash and cash equivalent | $ 132 | ||
Accounts receivable, after allowance for credit loss, current | $ 117 | 109 | |
Other assets, current | 9 | ||
Gathering, processing and transmission facilities | 209 | ||
Other property and equipment | 3 | ||
Accumulated depreciation, depletion, and amortization | 25 | ||
Equity method interests | 1,365 | ||
Deferred charges and other | 6 | ||
Accounts payable | 12 | ||
Other current liabilities | 15 | ||
Long-term debt | 657 | ||
Asset retirement obligation | 68 | ||
Other noncurrent liabilities | $ 67 | ||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
STATEMENT OF CONSOLIDATED CHANG
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - USD ($) $ in Millions | Total | Noncontrolling Interest, APA Corporation | Noncontrolling Interest, Sinopec | Noncontrolling Interest, Altus | Noncontrolling Interest, Egypt | Common Stock | Paid-In Capital | Accumulated Deficit | Treasury Stock | Accumulated Other Comprehensive Income (Loss) | PARENT COMPANY EQUITY (DEFICIT) | Noncontrolling Interests | Noncontrolling Interests Noncontrolling Interest, APA Corporation | Noncontrolling Interests Noncontrolling Interest, Sinopec | Noncontrolling Interests Noncontrolling Interest, Altus | Noncontrolling Interests Noncontrolling Interest, Egypt | ||
Beginning balance at Dec. 31, 2019 | $ 555 | |||||||||||||||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to Altus Preferred Unit limited partners | 76 | |||||||||||||||||
Distributions paid to Altus Preferred Unit limited partners | (23) | $ (91) | $ (91) | |||||||||||||||
Ending balance at Dec. 31, 2020 | 608 | |||||||||||||||||
Beginning balance at Dec. 31, 2019 | 4,465 | $ 261 | $ 11,769 | $ (5,601) | $ (3,190) | $ 16 | $ 3,255 | $ 1,210 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income/loss attributable to APA Corporation | (4,860) | (4,860) | (4,860) | |||||||||||||||
Net income (loss) attributable to noncontrolling interest | $ 0 | $ (121) | $ 1 | $ (121) | $ 1 | |||||||||||||
Distributions paid to Altus Preferred Unit limited partners | (23) | (91) | (91) | |||||||||||||||
Common dividends | (38) | (38) | (38) | |||||||||||||||
Common stock activity, net | (17) | 1 | (18) | (17) | ||||||||||||||
Compensation expense | 23 | 23 | 23 | |||||||||||||||
Other | (7) | (1) | 1 | (2) | (2) | (5) | ||||||||||||
Ending balance at Dec. 31, 2020 | (645) | 262 | 11,735 | (10,461) | (3,189) | 14 | (1,639) | 994 | ||||||||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to Altus Preferred Unit limited partners | 162 | |||||||||||||||||
Distributions paid to Altus Preferred Unit limited partners | (46) | (279) | (279) | |||||||||||||||
Distributions payable to Altus Preferred Unit limited partners | (12) | |||||||||||||||||
Ending balance at Dec. 31, 2021 | [1] | 712 | ||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income/loss attributable to APA Corporation | 1,062 | 1,062 | 1,062 | |||||||||||||||
Net income (loss) attributable to noncontrolling interest | 0 | 174 | 4 | 174 | 4 | |||||||||||||
Distributions paid to Altus Preferred Unit limited partners | (46) | (279) | (279) | |||||||||||||||
Common dividends | (9) | (9) | (9) | |||||||||||||||
Distributions to APA Corporation | (890) | (890) | (890) | |||||||||||||||
APA Corporation share exchange | 0 | (262) | (2,927) | 3,189 | ||||||||||||||
Holding Company Reorganization | 839 | 757 | 82 | 839 | ||||||||||||||
Other | 4 | 11 | 8 | 19 | (15) | |||||||||||||
Ending balance at Dec. 31, 2021 | 260 | [1] | 0 | 8,677 | (9,317) | 0 | 22 | (618) | 878 | |||||||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||||||||||||
Net income attributable to Altus Preferred Unit limited partners | (70) | |||||||||||||||||
Distributions paid to Altus Preferred Unit limited partners | (362) | (362) | ||||||||||||||||
Deconsolidation of Altus | (642) | |||||||||||||||||
Ending balance at Dec. 31, 2022 | [1] | 0 | ||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Net income/loss attributable to APA Corporation | 3,536 | 3,536 | 3,536 | |||||||||||||||
Net income (loss) attributable to noncontrolling interest | $ 278 | $ 464 | $ 14 | $ 278 | $ 464 | $ 14 | ||||||||||||
Distributions paid to Altus Preferred Unit limited partners | $ (362) | $ (362) | ||||||||||||||||
Distributions to APA Corporation | (894) | (678) | (678) | (216) | ||||||||||||||
Deconsolidation of Altus | (72) | (72) | ||||||||||||||||
Other | 18 | 26 | (8) | 18 | ||||||||||||||
Ending balance at Dec. 31, 2022 | $ 3,242 | [1] | $ 0 | $ 8,025 | $ (5,781) | $ 0 | $ 14 | $ 2,258 | $ 984 | |||||||||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
STATEMENT OF CONSOLIDATED CHA_2
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | ||
Common stock, dividends, per share (in USD per share) | $ 0.025 | $ 0.10 |
NATURE OF OPERATIONS
NATURE OF OPERATIONS | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Operations | Nature of Operations Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Prior to the BCP Business Combination defined below, Apache’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’s operating and legal structure, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below. Principles of Consolidation The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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. Noncontrolling interests represent outside ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. In conjunction with the ratification of a new merged concession agreement with the Egyptian General Petroleum Corporation (EGPC) in December 2021, Apache modified partnership agreements for certain consolidated subsidiaries. Apache subsequently determined that one of its limited partnership subsidiaries, which has control over Apache’s Egyptian operations, qualified as a variable interest entity (VIE) under GAAP. Apache continues to consolidate this limited partnership subsidiary because the Company has concluded that it has a controlling financial interest in the Egyptian operations and was determined to be the primary beneficiary of the VIE. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a minority participation in the remaining two-thirds of its consolidated Egypt oil and gas business as a noncontrolling interest. Refer to Note 2—Transactions with Parent Affiliate for detail regarding APA’s noncontrolling interest. All noncontrolling interests are reflected as a separate 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, 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 Apache consolidated because a wholly owned subsidiary of Apache had a controlling financial interest and was determined to be the primary beneficiary. Additionally, the assets of ALTM could only be used to settle obligations of ALTM. There was no recourse to the Company for ALTM’s liabilities. 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 3—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. 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 7—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 3—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 11—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 12—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited) ). 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). Recurring fair value measurements are presented in further detail in Note 5—Derivative Instruments and Hedging Activities , Note 7—Equity Method Intere s t s , Note 10—Debt and Financing Costs , Note 13—Retirement and Deferred Compensation Plans , and Note 14—Redeemable Noncontrolling Interest — Altus . The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments: For the Year Ended December 31, 2022 2021 2020 (In millions) Oil and gas proved property $ — $ — $ 4,319 Gathering, processing, and transmission facilities — — 68 Equity method interests — 160 — Goodwill — — 87 Inventory and other — 48 27 Total Impairments $ — $ 208 $ 4,501 For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in the EPIC crude oil pipeline (EPIC) as part of Altus’ review of the fair value of its assets in relation to the BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 3—Acquisitions and Divestitures for further detail on the BCP Business Combination. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea. For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with non-recurring fair value assessments. Given the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment based on the net book value of its assets as of March 31, 2020. The Company recognized proved property impairments of $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.” The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in the first quarter of 2020. During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S. Revenue Recognition Upstream The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to provide flexibility to fulfill sales obligations and commitments. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title. The Company’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer. On December 27, 2021, the Company announced the ratification of a new merged concession agreement (MCA) with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. For all periods presented, Sinopec has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a minority participation in the remaining two-thirds of its consolidated Egypt oil and gas business as a noncontrolling interest. Refer to Note 18—Business Segment Information for a disaggregation of revenue by product and reporting segment. Altus Midstream Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which were fully eliminated upon consolidation. Payment Terms and Contract Balances Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.3 billion at each of December 31, 2022 and 2021. 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. Cash and Cash Equivalents The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2022 and 2021, the Company had $185 million and $279 million, respectively, of cash and cash equivalents. As of December 31, 2021, approximately $132 million of cash was held by Altus, which was deconsolidated on February 22, 2022. The Company had no restricted cash as of December 31, 2022 and 2021. Accounts Receivable and Allowance for Credit Losses Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2022 2021 2020 (In millions) Allowance for credit loss at beginning of year $ 109 $ 95 $ 88 Additional provisions for the year 9 19 7 Uncollectible accounts written off, net of recoveries (1) (5) — Allowance for credit loss at end of year $ 117 $ 109 $ 95 Receivable from / Payable to APA Receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Cash will be transferred to Apache or paid to APA over time in order to manage affiliate balances for cash management purposes. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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 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. The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2020. The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2022 2021 2020 (In millions) Proved properties: U.S. $ — $ — $ 3,938 Egypt — — 374 North Sea — — 7 Total proved properties $ — $ — $ 4,319 Unproved properties: U.S. $ 20 $ 22 $ 92 Egypt 4 8 8 North Sea — 1 1 Total unproved properties $ 24 $ 31 $ 101 Proved properties impaired had an aggregate fair value as of the most recent date of impairment of $1.9 billion for 2020. 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 3—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $449 million and $673 million at December 31, 2022 and 2021, respectively, with accumulated depreciation for these assets totaling $367 million and $386 million for the respective periods. As a result of the BCP Business Combination, the Company deconsolidated $183 million of Altus GPT net assets on February 22, 2022. 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. Other Property and Equipment Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $206 million and $225 million at December 31, 2022 and 2021, respectively. Asset Retirement Costs and Obligations The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets. Capitalized Interest For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation. Goodwill Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense. Reductions in estimated net present value of |
TRANSACTIONS WITH PARENT AFFILI
TRANSACTIONS WITH PARENT AFFILIATE | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
TRANSACTIONS WITH PARENT AFFILIATE | TRANSACTIONS WITH PARENT AFFILIATE The Company completed the Holding Company Reorganization on March 1, 2021, and sold to APA all of the equity in the three Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The Company accounted for the divestiture of its subsidiaries as a transfer to an affiliate entity under common control and no longer consolidates the subsidiaries for periods subsequent to the Holding Company Reorganization. The carrying value of the net assets transferred was $483 million, which included approximately $292 million of cash and cash equivalents, $163 million of oil and gas properties, and working capital items. The Company continues to hold its existing assets in the U.S., Egypt, and the U.K. The Holding Company Reorganization gave rise to a note payable by APA to Apache. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the three subsidiaries sold by Apache to APA. The Company recognized interest income on this note of $63 million and $51 million during 2022 and 2021, respectively. The interest income related to this note is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2022, totaling $93 million, to PIK pursuant to the note. In the fourth quarter of 2021, in conjunction with the ratification of a new merged concession agreement (MCA) with EGPC, Apache entered into an agreement with APA under which the historical value of existing concessions prior to ratifying the MCA was retained by Apache, with any excess value from the MCA terms being allocated to APA. Sinopec owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business, and a portion of the remaining net income and distributable cash flow is allocated to APA in accordance with the terms of the agreement. In 2022, approximately 30 percent of the remaining net income and distributable cash flow for the Company’s Egyptian operations was allocated to APA. Apache consolidates its Egyptian operations, with noncontrolling interests reflected as a separate component in the Company’s consolidated balance sheet. During 2022, the Company recorded net income attributable to APA’s noncontrolling interest of $278 million, and distributed $216 million of cash to APA in association with its noncontrolling interest. The Company continues to provide administrative and support operations for certain APA subsidiaries with interest in the U.S., Suriname, and the Dominican Republic. The Company is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company in connection with its role as service provider. All reimbursements are based on actual costs incurred, and no market premium is applied by the Company to APA. The Company incurred $18 million and $17 million in reimbursable corporate overhead charges during 2022 and 2021, respectively. In August 2021, Apache entered into a promissory note with APA under which Apache could borrow up to $250 million from APA at APA’s discretion. The note had a term of one year and bore interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of December 31, 2021, there was $195 million outstanding under this note, which was reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet. All remaining borrowings were fully repaid prior to maturity on August 4, 2022. In April 2022, Apache made a promissory note payable to APA in the original principal amount of $680 million. Apache made the note in consideration for APA’s assumption under its U.S. dollar denominated syndicated facility on April, 29, 2022 of Apache’s borrowings outstanding upon the simultaneous termination of its 2018 syndicated facility, as described in Note 10—Debt and Financing Costs . The non-interest-bearing note had a term of one year, maturing on April 28, 2023, and was fully repaid by September 30, 2022. Apache repaid $331 million on the note during the second quarter of 2022 and the remaining $349 million during the third quarter of 2022. Receivable from APA Corporation, totaling $869 million and $77 million as of December 31, 2022 and 2021, respectively, represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Cash will be transferred to Apache over time in order to manage affiliate balances for cash management purposes. From time to time, the Company may, at its discretion, make distributions of capital to APA Corporation. During 2022, the Company made capital distributions totaling $894 million, primarily in support of APA Corporation’s share repurchase program, dividend payments made by APA, and distributions for APA’s noncontrolling interest during the period. During 2021, the Company made capital distributions totaling $839 million related to dividend payments made by APA. |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2022 | |
Business Combinations [Abstract] | |
ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES 2022 Activity During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million. During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million, recognizing a gain of approximately $36 million, upon closing of these transactions. During the first quarter of 2022, the Company completed a previously announced 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 and the fair value of its approximate 20 percent retained ownership in the combined entity. A summary of components of the gain, including the ALTM balance sheet amounts deconsolidated at the time of close, is included below: As of February 22, 2022 (In millions) Fair value of Kinetik Class A Common Stock held by Company $ 802 ASSETS: Cash and cash equivalents $ 143 Other current assets 29 Property and equipment, net 184 Equity method interests 1,367 Other noncurrent assets 12 Total assets deconsolidated $ 1,735 LIABILITIES: Current liabilities $ 3 Long-term debt 657 Other noncurrent liabilities 168 Total liabilities deconsolidated $ 828 NONCONTROLLING INTERESTS: Redeemable noncontrolling interest preferred unit limited partners $ 642 Noncontrolling interest-Altus 72 Total noncontrolling interests deconsolidated $ 714 Net effect of deconsolidating balance sheet $ (193) Gain on deconsolidation of ALTM $ 609 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 7—Equity Method Interests for further detail. In connection with this secondary offering, the Company agreed that, within 24 months of closing the offering, it will invest a minimum of $100 million of the proceeds of the offering for new well drilling and completion activity at the Alpine High play in the Delaware Basin, where Kinetik has exclusive gas and NGL gathering and processing rights. The Company has invested approximately half of this commitment as of year-end 2022. 2021 Activity During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $63 million in connection with the sale. During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions. During 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million. 2020 Activity During 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million. Also during 2020, the Company completed the sale of certain non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million, and recognized a gain of $13 million. The Company also recognized a gain of $19 million during 2020 in connection with a joint venture agreement with TotalEnergies (formerly Total S.A.) to explore and develop Block 58 offshore Suriname. |
CAPITALIZED EXPLORATORY WELL CO
CAPITALIZED EXPLORATORY WELL COSTS | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
CAPITALIZED EXPLORATORY WELL COSTS | CAPITALIZED EXPLORATORY WELL COSTS The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2022, 2021, and 2020. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. For the Year Ended December 31, 2022 2021 2020 (In millions) Capitalized well costs at beginning of year $ 46 $ 197 $ 141 Additions pending determination of proved reserves 138 62 226 Divestitures and other — (163) (38) Reclassifications to proved properties (110) (40) (56) Charged to exploration expense (24) (10) (76) Capitalized well costs at end of year $ 50 $ 46 $ 197 The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31: 2022 2021 2020 (In millions) Exploratory well costs capitalized for a period of one year or less $ 34 $ 13 $ 184 Exploratory well costs capitalized for a period greater than one year 16 33 13 Capitalized well costs at end of year $ 50 $ 46 $ 197 Number of projects with exploratory well costs capitalized for a period greater than one year 10 9 5 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 reserves can be attributed to these projects. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling were $16 million at December 31, 2022. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing. Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2021 totaled $24 million. These expenses pertain to projects in the North Sea where development is no longer progressing. The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2022, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2021 2020 2019 (In millions) Egypt $ 14 $ 5 $ — $ 9 North Sea 2 2 — — $ 16 $ 7 $ — $ 9 |
DERIVATIVE INSTRUMENTS AND HEDG
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES | 12 Months Ended |
Dec. 31, 2022 | |
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 may utilize 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. In December 2022, counterparty agreements for Apache’s commodity derivative instruments were transferred from Apache to APA Corporation. As of the dates of transfer, Apache’s consolidated balance sheet reflected derivative liabilities totaling $37 million, which represented the fair values of the commodity derivative instruments on those dates. The resulting impacts of the transfer to APA Corporation were the realization of the mark-to-market loss of $37 million on Apache’s statement of consolidated operation and the derecognition of open derivative positions on Apache’s consolidated balance sheet. Apache had no outstanding derivative positions as of December 31, 2022. Embedded Derivatives Altus Preferred Units Embedded Derivative The Altus Preferred Units embedded derivative was deconsolidated as of March 31, 2022 as part of the BCP Business Combination. Refer to Note 3 — Acquisitions and Divestitures for discussion of the BCP Business Combination and Note 14—Redeemable Noncontrolling Interest — Altus for a description of the Altus Preferred Units and associated embedded derivative. Pipeline Capacity Embedded Derivatives During the fourth quarter of 2019 and first quarter of 2020, the Company entered into agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements were arrangements under which the Company received payments calculated based on pricing differentials between Houston Ship Channel and Waha during the calendar years 2020 and 2021. This feature required bifurcation and measurement of the change in market value throughout 2020 and 2021. Unrealized gains and losses in the fair value of this feature were recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations, and the balance at the end of December 31, 2021 will be amortized into income over the original tenure of the host contract. 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 (Level 1) Significant Other Inputs (Level 2) Significant Unobservable Inputs Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2022 Assets: Commodity derivative instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity derivative instruments $ — $ — $ — $ — $ — $ — December 31, 2021 Liabilities: Commodity derivative instruments $ — $ 10 $ — $ 10 $ — $ 10 Pipeline capacity embedded derivatives — 46 — 46 — 46 Preferred Units embedded derivative — — 57 57 — 57 (1) Derivative fair values were 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 were not actively quoted in the open market. The Company primarily used 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 were reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values were recorded by netting asset and liability positions where counterparty master netting arrangements contained provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet were as follows: For the Year Ended December 31, 2022 2021 (In millions) Current Assets: Other current assets $ — $ — Other Assets: Deferred charges and other — — Total derivative assets $ — $ — Current Liabilities: Other current liabilities $ — $ 4 Deferred Credits and Other Noncurrent Liabilities: Other — 109 Total derivative liabilities $ — $ 113 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 Year Ended December 31, 2022 2021 2020 (In millions) Realized: Commodity derivative instruments $ (72) $ 25 $ (135) Foreign currency derivative instruments (13) — (1) Realized gain (loss), net (85) 25 (136) Unrealized: Commodity derivative instruments 9 (20) 11 Pipeline capacity embedded derivatives — 7 (61) Foreign currency derivative instruments — — (1) Preferred Units embedded derivative (31) 82 (36) Unrealized gain (loss), net (22) 69 (87) Derivative instrument gains (losses), net $ (107) $ 94 $ (223) Derivative instrument gains and losses were 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 were reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.” |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2022 | |
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 as of December 31: 2022 2021 (In millions) Inventories $ 425 $ 438 Drilling advances 64 55 Prepaid assets and other 54 56 Current decommissioning security for sold Gulf of Mexico assets 450 100 Total Other current assets $ 993 $ 649 |
EQUITY METHOD INTERESTS
EQUITY METHOD INTERESTS | 12 Months Ended |
Dec. 31, 2022 | |
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 and dividends received are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations. The 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 3–Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its Common Stock. Also during 2022, the Company received approximately 1.1 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends. Finally, in 2022, the Company recorded fair value adjustments on its ownership in Kinetik totaling a gain of approximately $32 million. The Company’s ownership of 18.9 million shares represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock as of December 31, 2022. The following table presents the activity in the Company’s equity method interest in Kinetik for the year ended December 31, 2022: Kinetik Holdings Inc (In millions) Balance at December 31, 2021 $ — Initial interest upon closing the BCP Business Combination 802 Sale of Class A shares (250) Paid-in-kind dividend 40 Fair value adjustments 32 Balance at December 31, 2022 $ 624 During the year ending December 31, 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the BCP Business Combination transaction totaling $91 million. As of December 31, 2022, the Company has recorded accrued GPT costs payable to Kinetik of approximately $17 million. In addition, the Company sold natural gas and NGLs to Kinetik during 2022 totaling $8 million. As of December 31, 2022, the Company has recorded accrued receivables from Kinetik of approximately $8 million. Prior to the deconsolidation of Altus on February 22, 2022, the Company, through its ownership of Altus, had the following equity method interests in four Permian Basin long-haul pipeline entities, which were accounted for under the equity method of accounting at December 31, 2021. For each of the equity method interests, Altus had the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentages held by the Company and associated carrying values for each entity: Interest December 31, 2021 (In millions) Gulf Coast Express Pipeline LLC 16.0 % $ 274 EPIC Crude Holdings, LP 15.0 % — Permian Highway Pipeline LLC 26.7 % 630 Shin Oak Pipeline (Breviloba, LLC) 33.0 % 461 Total Altus equity method interests $ 1,365 The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2022 and 2021: Gulf Coast Express Pipeline LLC EPIC Crude Holdings, LP Permian Highway Pipeline LLC Breviloba, LLC Total (In millions) Balance at December 31, 2020 $ 284 $ 176 $ 615 $ 480 $ 1,555 Capital contributions — 2 26 — 28 Distributions (50) — (74) (49) (173) Equity income (loss), net 40 (19) 63 30 114 Accumulated other comprehensive loss — 1 — — 1 Impairment (1) — (160) — — (160) Balance at December 31, 2021 274 — 630 461 1,365 Capital contributions — 2 — — 2 Distributions (5) — (9) (7) (21) Equity income (loss), net 8 (2) 10 5 21 Deconsolidation of Altus (277) — (631) (459) (1,367) Balance at December 31, 2022 $ — $ — $ — $ — $ — (1) Prior to the deconsolidation of Altus on February 22, 2022, the Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies for further details on this impairment charge. For discussion of the financial statement impacts related to the deconsolidation of ALTM, refer to Note 3—Acquisitions and Divestitures . |
OTHER CURRENT LIABILITIES
OTHER CURRENT LIABILITIES | 12 Months Ended |
Dec. 31, 2022 | |
Payables and Accruals [Abstract] | |
OTHER CURRENT LIABILITIES | OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities as of December 31: 2022 2021 (In millions) Accrued operating expenses $ 139 $ 129 Accrued exploration and development 300 206 Accrued compensation and benefits 514 292 Accrued interest 96 107 Accrued income taxes 90 28 Current asset retirement obligation 55 41 Current operating lease liability 167 99 Current decommissioning contingency for sold Gulf of Mexico properties 450 100 Other 238 168 Total Other current liabilities $ 2,049 $ 1,170 |
ASSET RETIREMENT OBLIGATION
ASSET RETIREMENT OBLIGATION | 12 Months Ended |
Dec. 31, 2022 | |
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 for the years ended December 31, 2022 and 2021: For the Year Ended December 31, 2022 2021 (In millions) Asset retirement obligation at beginning of the year $ 2,130 $ 1,944 Liabilities incurred 4 3 Liabilities divested (73) (44) Liabilities settled (39) (32) Accretion expense 117 113 Revisions in estimated liabilities (148) 146 Asset retirement obligation at end of the year 1,991 2,130 Less current portion (55) (41) Asset retirement obligation, long-term $ 1,936 $ 2,089 The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance. During 2022 and 2021, the Company recorded $4 million and $3 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2022, net abandonment costs were revised downward approximately $148 million to reflect changes in estimates of timing, activity costs, and foreign currency exchange rates on service costs, primarily in the North Sea. This downward revision was partially offset by an upward revision in the U.S. During 2021, approximately $146 million net abandonment costs were revised upward to reflect changes in estimates of higher activity costs and long-term inflation assumptions, primarily in the U.S. |
DEBT AND FINANCING COSTS
DEBT AND FINANCING COSTS | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
DEBT AND FINANCING COSTS | DEBT AND FINANCING COSTS Overview The debt of Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company to repurchase outstanding notes and debentures upon certain changes in control. None of the indentures contain prepayment obligations in the event of a decline in credit ratings. On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s former senior revolving credit facility, and for general corporate purposes. On August 18, 2020, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases. During 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under Apache’s former revolving credit facility. During the quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases. During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions. 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. During the quarter ended March 31, 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 quarter ended March 31, 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 October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, 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 in part by Apache’s borrowing under the U.S. dollar-denominated revolving credit facility of APA Corporation described below. Apache intends to reduce debt outstanding under its indentures from time to time. The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations. The following table presents the carrying value of the Company’s debt as of December 31, 2022 and 2021: December 31, 2022 2021 (In millions) 3.25% notes due 2022 (1) $ — $ 213 2.625% notes due 2023 (2) — 123 4.625% notes due 2025 (3) 51 500 7.7% notes due 2026 78 79 7.95% notes due 2026 132 133 4.875% due 2027 (3) 108 378 4.375% notes due 2028 (3) 325 703 7.75% notes due 2029 (3)(4) 235 235 4.25% notes due 2030 (3) 579 580 6.0% notes due 2037 (3) 443 443 5.1% notes due 2040 (3) 1,333 1,333 5.25% notes due 2042 (3) 399 399 4.75% notes due 2043 (3) 428 428 4.25% notes due 2044 (3) 221 221 7.375% debentures due 2047 150 150 5.35% notes due 2049 (3) 387 387 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (5) 4,908 6,344 Altus credit facility (6) — 657 Syndicated credit facilities (6)(7) — 542 Finance lease obligations 34 36 Unamortized discount (27) (30) Debt issuance costs (28) (39) Total debt 4,887 7,510 Current maturities (2) (215) Long-term debt $ 4,885 $ 7,295 (1) On January 18, 2022, Apache redeemed the 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. (2) On October 17, 2022, Apache redeemed the 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. (3) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable. (4) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (5) The fair values of Apache’s notes and debentures were $4.2 billion and $7.1 billion as of December 31, 2022 and 2021, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (6) The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates. (7) Although Apache had no borrowings under APA’s syndicated credit facilities as of December 31, 2022, Apache currently is a guarantor of obligations under those facilities. Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2022 are as follows: (In millions) 2023 $ — 2024 — 2025 51 2026 210 2027 108 Thereafter 4,539 Notes and debentures, excluding discounts and debt issuance costs $ 4,908 Uncommitted Lines of Credit The Company from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2022 and 2021, there were no outstanding borrowings under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2021, there were £117 million and $17 million in letters of credit outstanding under these facilities. Unsecured Committed Bank Credit Facilities On April 29, 2022, Apache entered into two unsecured guaranties of obligations under two unsecured syndicated credit agreements then entered into by APA Corporation (APA), of which Apache is a wholly owned subsidiary. APA’s new credit agreements are for general corporate purposes and replaced and refinanced Apache’s 2018 syndicated credit agreement (the Former Facility). • One credit 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). APA 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 APA’s two, one-year extension options. • The second credit 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 APA’s two, one-year extension options. In connection with APA’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 APA’s 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 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. As of December 31, 2021, there were $542 million of borrowings and an aggregate £748 million and $20 million in letters of credit outstanding under the Former Facility. 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. All borrowings under the USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin ranging from 0.10% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.10% to 1.675% (Applicable Margin). All borrowings under the GBP Agreement bear interest at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average published by the Bank of England, plus the Applicable Margin. Each New Agreement also requires the borrower to pay quarterly a facility fee on total commitments. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2022, Apache’s Long-Term Debt Rating applied, and the Base Rate Margin was 0.60%, the Applicable Margin was 1.60%, and the facility fee was 0.275%. A commission is payable quarterly to lenders under each New Agreement on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks. Borrowers under each New Agreement, which may include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default substantially similar to those in the Former Facility, such as: • A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital continues to exclude the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2022, APA’s debt-to-capital ratio as calculated under each New Agreement was 21 percent. • A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $1.5 billion as of December 31, 2022. • Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold. • Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries. Consistent with the Former Facility, the New Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings. Apache was in compliance with applicable terms of each New Agreement as of December 31, 2022. In November 2018, Altus and its subsidiary, Altus Midstream LP (Altus LP), were subsidiaries of Apache, and Altus LP entered into an unsecured revolving credit facility for general corporate purposes. The agreement for the facility, as amended, provided aggregate commitments from a syndicate of banks of $800 million, including a letter of credit subfacility. The credit facility was not guaranteed by APA, Apache, or any of APA’s other subsidiaries. On February 22, 2022, Altus was deconsolidated from APA and Apache. As of December 31, 2021, there were $657 million of borrowings and $2 million letters of credit outstanding under the facility. Financing Costs, Net The following table presents the components of the Company’s financing costs, net: For the Year Ended December 31, 2022 2021 2020 (In millions) Interest expense $ 312 $ 419 $ 438 Amortization of debt issuance costs 7 8 8 Capitalized interest (1) — (12) Loss (gain) on extinguishment of debt 67 104 (160) Interest income (9) (8) (7) Interest income from APA Corporation, net (63) (51) — Financing costs, net $ 313 $ 472 $ 267 As of December 31, 2022, the Company had $28 million of debt issuance costs, which will be charged to financing costs over the life of the related debt issuances. Discount amortization of $2 million, $6 million, and $7 million was recorded as interest expense in 2022, 2021, and 2020, respectively. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income (loss) before income taxes was composed of the following: For the Year Ended December 31, 2022 2021 2020 (In millions) U.S. $ 2,656 $ 689 $ (4,581) Foreign 3,218 1,291 (259) Total $ 5,874 $ 1,980 $ (4,840) The total income tax provision consisted of the following: For the Year Ended December 31, 2022 2021 2020 (In millions) Current income taxes: Federal $ 1 $ 16 $ (2) State 11 — — Foreign 1,495 636 178 1,507 652 176 Deferred income taxes: Federal — — — Foreign 145 (74) (112) 145 (74) (112) Total $ 1,652 $ 578 $ 64 The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below: For the Year Ended December 31, 2022 2021 2020 (In millions) Income tax expense (benefit) at U.S. statutory rate $ 1,234 $ 416 $ (1,016) State income tax, less federal effect (1) 9 — — Taxes related to foreign operations 774 300 97 Tax credits (4) (10) (13) Net change in tax contingencies 1 16 1 Goodwill impairment — — 35 Valuation allowances (1) (705) (111) 965 Tax adjustments attributable to BCP Business Combination 126 — — Remeasurement of U.K. deferred tax liability 208 — — Tax attributable to Altus Preferred Unit limited partners — (34) (16) All other, net 9 1 11 $ 1,652 $ 578 $ 64 (1) The change in state valuation allowance is included as a component of state income tax. The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax liability consisted of the following as of December 31: 2022 2021 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,035 $ 2,494 Capital losses 357 647 Tax credits and other tax incentives 26 24 Foreign tax credits 2,241 2,241 Accrued expenses and liabilities 145 152 Asset retirement obligation 672 712 Property and equipment — 3 Investment in Altus Midstream LP — 64 Net interest expense limitation 55 135 Lease liability 113 81 Decommissioning contingency for sold Gulf of Mexico properties 275 263 Other — 1 Total deferred tax assets 5,919 6,817 Valuation allowance (4,831) (5,875) Net deferred tax assets 1,088 942 Deferred tax liabilities: Equity investments 1 2 Property and equipment 1,014 748 Right-of-use asset 110 77 Decommissioning security for sold Gulf of Mexico properties 148 164 Other 90 86 Total deferred tax liabilities 1,363 1,077 Net deferred income tax liability $ 275 $ 135 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2022 2021 (In millions) Assets: Deferred charges and other $ 39 $ 13 Liabilities: Income taxes 314 148 Net deferred income tax liability $ 275 $ 135 On January 14, 2022, Apache Midstream LLC, a wholly owned subsidiary of Apache, exchanged 12.5 million Common Units in Altus Midstream LP for 12.5 million shares of ALTM Class A Common Stock, in a taxable exchange. On February 22, 2022, as a result of the BCP Business Combination, the Company deconsolidated ALTM. On March 11, 2022, the Company sold four million of its shares of Kinetik Class A Common Stock. The Company recorded tax expense of $126 million associated with the BCP Business Combination. The tax impact of the BCP Business Combination was fully offset by a change in valuation allowance. Refer to Note 3— Acquisitions and Divestitures for further detail. On May 26, 2022, the U.K. Chancellor of the Exchequer announced a new tax (the Energy Profits Levy) on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Under the new law, an additional levy is assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Company recorded a deferred tax expense of $208 million associated with the remeasurement of the U.K. deferred tax liability. On November 17, 2022, the U.K. Chancellor of the Exchequer announced in the Autumn Statement 2022 further changes to the Energy Profits Levy, increasing the levy assessed from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023, through March 31, 2028. On November 22, 2022, the U.K. Government published draft legislation to implement this change, among other provisions, and on January 10, 2023, the Finance Act 2023 was enacted, receiving Royal Assent. 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 expects to record a deferred tax expense of approximately $170 million to $190 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 adjusted 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. The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. A significant piece of negative evidence evaluated was the U.S. pre-tax book cumulative loss incurred over the three-year period ended December 31, 2022. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months the U.S. will exit its cumulative loss, allowing the Company to reach a conclusion that a material portion of the U.S. valuation allowance may 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. In 2022, 2021, and 2020, the Company’s valuation allowance decreased by $1.0 billion, decreased by $116 million, and increased by $1.0 billion, respectively, as detailed in the table below: 2022 2021 2020 (In millions) Balance at beginning of year $ 5,875 $ 5,991 $ 4,959 State (1) (111) 1 67 U.S. (706) (112) 960 Foreign (227) (5) 5 Balance at end of year $ 4,831 $ 5,875 $ 5,991 (1) Reported as a component of state income taxes. On December 31, 2022, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 7,968 2027 - Indefinite State 6,505 Various The Company has a U.S. net operating loss carryforward of $8.0 billion, which includes $82 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $6.5 billion, a net interest expense carryover of $246 million under Section 163(j) of the Code subject to indefinite carryover, and a U.S. capital loss carryforward of $1.6 billion, which has a five year carryover period expiring between 2023-2027. The Company has recorded a full valuation allowance against the U.S. net operating losses, the state net operating losses, the net interest expense carryover, and the U.S. capital loss because it is more likely than not that these attributes will not be realized. On December 31, 2022, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,241 2025-2026 The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a full valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized. The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold that a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2022 2021 2020 (In millions) Balance at beginning of year $ 116 $ 93 $ 82 Additions based on tax positions related to prior year — 16 — Additions based on tax positions related to the current year — 7 11 Reductions for tax positions of prior years (27) — — Balance at end of year $ 89 $ 116 $ 93 The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2022, 2021, and 2020, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2022, 2021, and 2020, the Company had an accrued liability for interest and penalties of $5 million, $4 million, and $3 million, respectively. In 2022, 2021, and 2020, the Company recorded a $27 million net decrease, a $23 million net increase, and an $11 million net increase, respectively, in its reserve for uncertain tax positions. On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice. Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. Apache’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2021 |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
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 December 31, 2022, the Company has an accrued liability of approximately $64 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. For material matters that 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. 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 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 2022, 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 plaintiff’s claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. 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 believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity. 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. The Company believes that plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity. 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. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore . As a result, the California cases were sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state court. The 9 th Circuit has since, once again, affirmed the district court’s remand to state court. The defendants are appealing this latest remand decision to the U.S. Supreme Court. 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. After removal of this lawsuit to federal court, the district court remanded it back to state court. The 3 rd Circuit has since, once again, affirmed the district court’s remand to state court. The defendants are appealing this latest remand decision to the U.S. Supreme Court. The Company believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit. Castex Lawsuit In a case styled Apache Corporation v. Castex Offshore, Inc., et. al. , Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company. Further appeal is pending. 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 believes that plaintiffs’ claims lack merit and 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. The case purports to be a derivative action 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 believe that plaintiff’s claims lack merit and intend to vigorously defend this lawsuit. Environmental Matters The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition. As of December 31, 2022, the Company had an undiscounted reserve for environmental remediation of approximately $1 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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs. 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; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs. The Company is not aware of any environmental claims existing as of December 31, 2022 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. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure 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 decommissioning of Legacy GOM Assets. By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, 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 notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. 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. If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache expects to obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until 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 ordered by BSEE to perform, 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 December 31, 2022, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion 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 $1.2 billion as of December 31, 2022, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $738 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $450 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 December 31, 2022, the Company has also recorded a $667 million asset, which represents the 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, $217 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current assets.” The Company recognized $157 million and $446 million during 2022 and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations. Leases and Contractual Obligations The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, Apache records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, Apache enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable. As allowed under ASU 2016-02, “Leases (Topic 842),” the Company applied practical expedients permitting an entity the option to not evaluate under such standard those existing or expired land easements that were not previously accounted for as leases as well as permitting an entity the option to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs. Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $144 million, $127 million, and $149 million for the years ended 2022, 2021, and 2020, respectively. As allowed under the standard, Apache elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “ Current debt Long-term debt The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2022: Operating Leases Finance Lease Weighted average remaining lease term 2.5 years 10.7 years Weighted average discount rate 3.7 % 4.4 % At December 31, 2022, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2023 $ 174 $ 3 $ 222 2024 102 3 183 2025 14 4 163 2026 6 4 1,951 2027 6 4 133 Thereafter 11 27 333 Total future minimum payments 313 45 $ 2,985 Less: imputed interest (14) (11) N/A Total lease liabilities 299 34 N/A Current portion 167 2 N/A Non-current portion $ 132 $ 32 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $183 million, $194 million, and $120 million in 2022, 2021, and 2020, respectively. (5) Under terms agreed to in the new Egypt merged concession agreement, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2022, the Company has spent $1.7 billion and believes it will be able to satisfy the remaining obligation within its current exploration and development program. The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $89 million, $63 million, and $41 million in 2022, 2021, and 2020, respectively. In addition to the lease liabilities in the table above, at December 31, 2022, undiscounted fixed minimum payments for operating leases not yet commenced totaled $207 million. The leases primarily relate to office leases in Houston and Egypt, and estimated cash payments for 2023 are not expected to be material. The underlying assets for these leases were primarily designed by the lessors, and the Company is in the process of designing leasehold improvements for both leases. |
RETIREMENT AND DEFERRED COMPENS
RETIREMENT AND DEFERRED COMPENSATION PLANS | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
RETIREMENT AND DEFERRED COMPENSATION PLANS | RETIREMENT AND DEFERRED COMPENSATION PLANSThe Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute to the plan up to 50 percent of eligible compensation as defined in the plan, with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan. Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a qualifying change in control of ownership of APA Corporation, as defined in the applicable plan, immediate and full vesting occurs. The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $40 million, $31 million, and $43 million for 2022, 2021, and 2020, respectively. The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003. Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare. The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2022, 2021, and 2020, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans. 2022 2021 2020 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 211 $ 20 $ 233 $ 20 $ 199 $ 20 Service cost 2 1 3 1 3 1 Interest cost 3 — 3 — 4 — Foreign currency exchange rates (21) — (2) — 8 — Actuarial losses (gains) (79) (5) (5) 1 30 1 Plan settlements — — (17) — — — Benefits paid (8) (3) (4) (4) (11) (4) Retiree contributions — 2 — 2 — 2 Projected benefit obligation at end of year 108 15 211 20 233 20 Change in Plan Assets Fair value of plan assets at beginning of year 254 — 262 — 228 — Actual return (loss) on plan assets (87) — 11 — 31 — Foreign currency exchange rates (26) — (3) — 9 — Employer contributions 4 2 5 2 5 2 Plan settlements — — (17) — — — Benefits paid (8) (4) (4) (4) (11) (4) Retiree contributions — 2 — 2 — 2 Fair value of plan assets at end of year 137 — 254 — 262 — Funded status at end of year $ 29 $ (15) $ 43 $ (20) $ 29 $ (20) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (13) 43 (18) 29 (18) $ 29 $ (15) $ 43 $ (20) $ 29 $ (20) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (10) $ 18 $ 1 $ 14 $ (11) $ 16 Weighted Average Assumptions used as of December 31 Discount rate 5.00 % 5.29 % 1.80 % 2.57 % 1.40 % 2.06 % Salary increases 4.70 % N/A 4.90 % N/A 4.50 % N/A Expected return on assets 4.70 % N/A 1.90 % N/A 1.50 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.00 % Ultimate in 2028 N/A 5.25 % N/A 5.00 % N/A 5.00 % As of December 31, 2022, 2021, and 2020, the accumulated benefit obligation for the U.K. Pension Plan was $89 million, $205 million, and $207 million, respectively. The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in a blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below: Target Percentage of 2022 2022 2021 Asset Category Equity securities: Overseas quoted equities 14 % 15 % 15 % Total equity securities 14 % 15 % 15 % Debt securities: U.K. government bonds 52 % 52 % 54 % U.K. corporate bonds 32 % 32 % 25 % Total debt securities 84 % 84 % 79 % Cash 2 % 1 % 6 % Total 100 % 100 % 100 % The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2022 and 2021 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2022 and 2021: December 31, 2022 2021 (In millions) Equity securities: Overseas quoted equities $ 20 $ 38 Total equity securities 20 38 Debt securities: U.K. government bonds 71 138 U.K. corporate bonds 44 62 Total debt securities 115 200 Cash 2 16 Fair value of plan assets $ 137 $ 254 The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year. The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2022, 2021, and 2020: 2022 2021 2020 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 2 $ 1 $ 3 $ 1 $ 3 $ 1 Interest cost 3 — 3 — 4 — Expected return on assets (4) — (4) — (5) — Amortization of loss — (1) — (1) — (1) Settlement loss — — — — — — Net periodic benefit cost $ 1 $ — $ 2 $ — $ 2 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 1.80 % 2.57 % 1.40 % 2.06 % 2.10 % 3.00 % Salary increases 4.90 % N/A 4.50 % N/A 4.30 % N/A Expected return on assets 1.90 % N/A 1.50 % N/A 2.20 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.00 % N/A 6.25 % Ultimate in 2028 N/A 5.00 % N/A 5.00 % N/A 5.00 % The Company expects to contribute approximately $2 million to its pension plan and $3 million to its postretirement benefit plan in 2023. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2023 $ 5 $ 2 2024 5 2 2025 5 2 2026 5 1 2027 5 1 Years 2028-2032 28 6 |
REDEMABLE NONCONTROLLING INTERE
REDEMABLE NONCONTROLLING INTEREST - ALTUS | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
REDEMABLE NONCONTROLLING INTEREST - ALTUS | REDEEMABLE NONCONTROLLING INTEREST — ALTUS Preferred Units Issuance On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Classification Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto. Measurement Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Pursuant to this method, the net transaction price was accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment was limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end was equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price. Activity related to the Preferred Units for the 2022 and 2021 periods is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2020 660,694 $ 608 Cash distributions to Altus Preferred Unit limited partners — (46) Distributions payable to Altus Preferred Unit limited partners — (12) Allocation of Altus Midstream net income N/A 80 Accreted value adjustment N/A 82 Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2021 660,694 712 Allocation of Altus Midstream LP net income N/A 12 Accreted value adjustment (1) N/A (82) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at February 22, 2022 660,694 642 Preferred Units embedded derivative 89 Deconsolidation of Altus (731) $ — (1) Includes the reversal of previously recorded accreted value adjustments due to the deconsolidation of Altus. N/A - not applicable. Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization and subsequent activity, Apache recorded various intercompany activities during the quarter ended March 31, 2021 as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail. Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache. Net Income (Loss) per Common Share Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly owned subsidiary of APA. Stock Compensation Plans Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting. On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2022, 10.1 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash. Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs: For the Year Ended December 31, 2022 2021 2020 (In millions) Stock-settled and cash-settled compensation expensed $ 288 $ 152 $ 40 Stock-settled and cash-settled compensation capitalized 43 18 7 Total stock-settled and cash-settled compensation costs $ 331 $ 170 $ 47 Stock Options As of December 31, 2022, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted. The following table summarizes stock option activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 3,012 $ 63.79 3,537 $ 72.10 4,298 $ 75.24 Exercised (99) 42.09 — — — — Forfeited (2) 49.10 — — (37) 44.98 Expired (833) 81.56 (525) 119.83 (724) 92.14 Outstanding, end of year (1) 2,078 57.71 3,012 63.79 3,537 72.10 Expected to vest — — — — 150 45.77 Exercisable, end of year (1) 2,078 57.71 3,012 63.79 3,387 73.26 (1) As of December 31, 2022, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $3.5 million. There were no options issued and 98,646 options exercised during the year ended December 31, 2022. There were no options issued and no options exercised during the years ended December 31, 2021, and 2020. Restricted Stock Units and Restricted Stock Phantom Units Prior to consummation of the Holding Company Reorganization, the Company had restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either APA’s common stock or, prior to the BCP Business Combination, in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. For the years ended December 31, 2022, 2021, and 2020, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $145 million, $91 million, and $39 million, respectively. As of December 31, 2022, 2021, and 2020, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $22 million, $15 million, and $6 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,073 $ 19.98 1,552 $ 28.43 2,448 $ 46.65 Granted 847 29.90 1,506 16.46 1,352 24.60 Vested (3) (978) 22.39 (857) 29.13 (1,933) 48.65 Forfeited (57) 23.49 (128) 19.78 (315) 30.09 Non-vested, end of year (1)(2) 1,885 23.08 2,073 19.98 1,552 28.43 (1) As of December 31, 2022, there was $14 million of total unrecognized compensation cost related to 1,885,491 unvested stock-settled restricted stock units. (2) As of December 31, 2022, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2022, 2021, and 2020 were approximately $22 million, $25 million, and $94 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2022, 2021, and 2020: For the Year Ended December 31, 2022 2021 2020 (In thousands) Non-vested, beginning of year 6,402 4,423 5,384 Adjustment for ALTM reverse stock split (1) — — (1,246) Adjustment from ALTM transaction (2) 143 — — Granted (3) 2,568 4,441 3,462 Vested (2,970) (2,049) (1,618) Forfeited (434) (413) (1,559) Non-vested, end of year (4) 5,709 6,402 4,423 (1) Prior to the deconsolidation of Altus on February 22, 2022, on June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards were based on the per-share market price of ALTM common stock. (2) Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price. (3) Restricted stock phantom units granted during 2022, 2021, and 2020 included 2,512,602, 4,375,546, and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 55,546, 65,327, and 83,239 awards, respectively, based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (4) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2022 was approximately $103 million. In January 2023, APA awarded 580,254 restricted stock units and 1,950,332 restricted stock phantom units based on APA’s weighted-average per-share market price of $42.15 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $24 million and $85 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. Performance Program To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2022, are as described below: • In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 23,633 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 23 percent of target. • In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 604,417 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 100 percent of target. • In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 1,311,715 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 155 percent of target. • In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,826,890 phantom units were outstanding as of December 31, 2022, from which a minimum of zero to a maximum of 3,653,780 units could be awarded. • In January 2022, the Company’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,068,530 phantom units were outstanding as of December 31, 2022, from which a minimum of zero to a maximum of 2,137,060 units could be awarded. Compensation costs charged to expense under the performance programs were an expense of $136 million, an expense of $56 million, and a credit of $8 million during 2022, 2021, and 2020, respectively. Capitalized compensation costs under the performance programs were an expense of $21 million, an expense of $3 million, and a credit of $1 million during 2022, 2021, and 2020, respectively. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2022: Units (In thousands) Non-vested, beginning of year 4,531 Granted 1,676 Vested (656) Forfeited (106) Expired (610) Non-vested, end of year (1) 4,835 (1) As of December 31, 2022, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $53 million. In January 2023, APA’s board of directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Payout for 40 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 60 percent of the shares is based on the performance and financial objectives defined in the 2023 Performance Program. Eligible employees received the initial cash-settled conditional phantom units totaling 797,429 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 1,594,858 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $62.15 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 60 percent was $44.06 based on the weighted-average fair market value of a share of common stock of APA as of the grant date. These 2023 Performance Program phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. |
CAPITAL STOCK AND EQUITY
CAPITAL STOCK AND EQUITY | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
CAPITAL STOCK AND EQUITY | REDEEMABLE NONCONTROLLING INTEREST — ALTUS Preferred Units Issuance On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Classification Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto. Measurement Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Pursuant to this method, the net transaction price was accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment was limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end was equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price. Activity related to the Preferred Units for the 2022 and 2021 periods is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2020 660,694 $ 608 Cash distributions to Altus Preferred Unit limited partners — (46) Distributions payable to Altus Preferred Unit limited partners — (12) Allocation of Altus Midstream net income N/A 80 Accreted value adjustment N/A 82 Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2021 660,694 712 Allocation of Altus Midstream LP net income N/A 12 Accreted value adjustment (1) N/A (82) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at February 22, 2022 660,694 642 Preferred Units embedded derivative 89 Deconsolidation of Altus (731) $ — (1) Includes the reversal of previously recorded accreted value adjustments due to the deconsolidation of Altus. N/A - not applicable. Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization and subsequent activity, Apache recorded various intercompany activities during the quarter ended March 31, 2021 as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail. Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache. Net Income (Loss) per Common Share Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly owned subsidiary of APA. Stock Compensation Plans Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting. On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2022, 10.1 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash. Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs: For the Year Ended December 31, 2022 2021 2020 (In millions) Stock-settled and cash-settled compensation expensed $ 288 $ 152 $ 40 Stock-settled and cash-settled compensation capitalized 43 18 7 Total stock-settled and cash-settled compensation costs $ 331 $ 170 $ 47 Stock Options As of December 31, 2022, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted. The following table summarizes stock option activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 3,012 $ 63.79 3,537 $ 72.10 4,298 $ 75.24 Exercised (99) 42.09 — — — — Forfeited (2) 49.10 — — (37) 44.98 Expired (833) 81.56 (525) 119.83 (724) 92.14 Outstanding, end of year (1) 2,078 57.71 3,012 63.79 3,537 72.10 Expected to vest — — — — 150 45.77 Exercisable, end of year (1) 2,078 57.71 3,012 63.79 3,387 73.26 (1) As of December 31, 2022, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $3.5 million. There were no options issued and 98,646 options exercised during the year ended December 31, 2022. There were no options issued and no options exercised during the years ended December 31, 2021, and 2020. Restricted Stock Units and Restricted Stock Phantom Units Prior to consummation of the Holding Company Reorganization, the Company had restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either APA’s common stock or, prior to the BCP Business Combination, in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. For the years ended December 31, 2022, 2021, and 2020, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $145 million, $91 million, and $39 million, respectively. As of December 31, 2022, 2021, and 2020, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $22 million, $15 million, and $6 million, respectively. The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,073 $ 19.98 1,552 $ 28.43 2,448 $ 46.65 Granted 847 29.90 1,506 16.46 1,352 24.60 Vested (3) (978) 22.39 (857) 29.13 (1,933) 48.65 Forfeited (57) 23.49 (128) 19.78 (315) 30.09 Non-vested, end of year (1)(2) 1,885 23.08 2,073 19.98 1,552 28.43 (1) As of December 31, 2022, there was $14 million of total unrecognized compensation cost related to 1,885,491 unvested stock-settled restricted stock units. (2) As of December 31, 2022, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2022, 2021, and 2020 were approximately $22 million, $25 million, and $94 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2022, 2021, and 2020: For the Year Ended December 31, 2022 2021 2020 (In thousands) Non-vested, beginning of year 6,402 4,423 5,384 Adjustment for ALTM reverse stock split (1) — — (1,246) Adjustment from ALTM transaction (2) 143 — — Granted (3) 2,568 4,441 3,462 Vested (2,970) (2,049) (1,618) Forfeited (434) (413) (1,559) Non-vested, end of year (4) 5,709 6,402 4,423 (1) Prior to the deconsolidation of Altus on February 22, 2022, on June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards were based on the per-share market price of ALTM common stock. (2) Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price. (3) Restricted stock phantom units granted during 2022, 2021, and 2020 included 2,512,602, 4,375,546, and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 55,546, 65,327, and 83,239 awards, respectively, based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (4) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2022 was approximately $103 million. In January 2023, APA awarded 580,254 restricted stock units and 1,950,332 restricted stock phantom units based on APA’s weighted-average per-share market price of $42.15 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $24 million and $85 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. Performance Program To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2022, are as described below: • In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 23,633 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 23 percent of target. • In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 604,417 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 100 percent of target. • In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 1,311,715 phantom units were outstanding as of December 31, 2022. The results for the performance period yielded a payout of 155 percent of target. • In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,826,890 phantom units were outstanding as of December 31, 2022, from which a minimum of zero to a maximum of 3,653,780 units could be awarded. • In January 2022, the Company’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,068,530 phantom units were outstanding as of December 31, 2022, from which a minimum of zero to a maximum of 2,137,060 units could be awarded. Compensation costs charged to expense under the performance programs were an expense of $136 million, an expense of $56 million, and a credit of $8 million during 2022, 2021, and 2020, respectively. Capitalized compensation costs under the performance programs were an expense of $21 million, an expense of $3 million, and a credit of $1 million during 2022, 2021, and 2020, respectively. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2022: Units (In thousands) Non-vested, beginning of year 4,531 Granted 1,676 Vested (656) Forfeited (106) Expired (610) Non-vested, end of year (1) 4,835 (1) As of December 31, 2022, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $53 million. In January 2023, APA’s board of directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Payout for 40 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 60 percent of the shares is based on the performance and financial objectives defined in the 2023 Performance Program. Eligible employees received the initial cash-settled conditional phantom units totaling 797,429 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 1,594,858 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $62.15 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 60 percent was $44.06 based on the weighted-average fair market value of a share of common stock of APA as of the grant date. These 2023 Performance Program phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Components of accumulated other comprehensive income (loss) include the following: As of December 31, 2022 2021 2020 (In millions) Share of equity method interests other comprehensive loss $ — $ — $ (1) Pension and postretirement benefit plan ( Note 13 ) 14 22 15 Accumulated other comprehensive income $ 14 $ 22 $ 14 |
MAJOR CUSTOMERS
MAJOR CUSTOMERS | 12 Months Ended |
Dec. 31, 2022 | |
Risks and Uncertainties [Abstract] | |
MAJOR CUSTOMERS | MAJOR CUSTOMERS The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2022, sales to EGPC accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs revenues. Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations. |
BUSINESS SEGMENT INFORMATION
BUSINESS SEGMENT INFORMATION | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
BUSINESS SEGMENT INFORMATION | BUSINESS SEGMENT INFORMATION As of December 31, 2022, the Company is 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 natural gas, crude oil and NGLs. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s midstream business was operated by Altus, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below: Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2022 Oil revenues $ 3,145 $ 1,232 $ 2,323 $ — $ — $ 6,700 Natural gas revenues 370 281 894 — — 1,545 Natural gas liquids revenues 6 45 735 — (3) 783 Oil, natural gas, and natural gas liquids production revenues 3,521 1,558 3,952 — (3) 9,028 Purchased oil and gas sales — — 1,850 5 — 1,855 Midstream service affiliate revenues — — — 16 (16) — 3,521 1,558 5,802 21 (19) 10,883 Operating Expenses: Lease operating expenses 526 404 506 — (1) 1,435 Gathering, processing, and transmission 22 43 304 5 (18) 356 Purchased oil and gas costs — — 1,776 — — 1,776 Taxes other than income — — 253 3 — 256 Exploration 84 35 24 — 3 146 Depreciation, depletion, and amortization 400 238 537 2 — 1,177 Asset retirement obligation accretion — 82 34 1 — 117 1,032 802 3,434 11 (16) 5,263 Operating Income (Loss) $ 2,489 $ 756 $ 2,368 $ 10 $ (3) 5,620 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of Mexico properties (157) Derivative instrument losses, net (107) Other 139 General and administrative (462) Transaction, reorganization, and separation (26) Financing costs, net (313) Income Before Income Taxes $ 5,874 Total Assets (3) $ 3,148 $ 1,911 $ 9,196 $ — $ — $ 14,255 Net Property and Equipment $ 1,976 $ 1,386 $ 4,595 $ — $ — $ 7,957 Additions to Net Property and Equipment $ 695 $ 210 $ 752 $ — $ — $ 1,657 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2021 Oil revenues $ 1,806 $ 929 $ 1,850 $ — $ — $ 4,585 Natural gas revenues 270 183 754 — — 1,207 Natural gas liquids revenues 9 24 676 — (3) 706 Oil, natural gas, and natural gas liquids production revenues 2,085 1,136 3,280 — (3) 6,498 Purchased oil and gas sales — — 1,476 11 — 1,487 Midstream service affiliate revenues — — — 127 (127) — 2,085 1,136 4,756 138 (130) 7,985 Operating Expenses: Lease operating expenses 469 383 391 — (2) 1,241 Gathering, processing, and transmission 12 39 309 32 (128) 264 Purchased oil and gas costs — — 1,575 5 — 1,580 Taxes other than income — — 190 14 — 204 Exploration 63 34 28 — 2 127 Depreciation, depletion, and amortization 524 270 554 12 — 1,360 Asset retirement obligation accretion — 79 30 4 — 113 Impairments 26 22 — 160 — 208 1,094 827 3,077 227 (128) 5,097 Operating Income (Loss) $ 991 $ 309 $ 1,679 $ (89) $ (2) 2,888 Other Income (Expense): Gain on divestitures, net 67 Losses on previously sold Gulf of Mexico properties (446) Derivative instrument gains, net 94 Other 228 General and administrative (357) Transaction, reorganization, and separation (22) Financing costs, net (472) Income Before Income Taxes $ 1,980 Total Assets (3) $ 2,796 $ 2,199 $ 7,700 $ 1,698 $ — $ 14,393 Net Property and Equipment $ 1,720 $ 1,646 $ 4,507 $ 187 $ — $ 8,060 Additions to Net Property and Equipment $ 319 $ 159 $ 523 $ 3 $ — $ 1,004 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2020 Oil revenues $ 1,102 $ 795 $ 1,209 $ — $ — $ 3,106 Natural gas revenues 280 67 251 — — 598 Natural gas liquids revenues 8 21 304 — — 333 Oil, natural gas, and natural gas liquids production revenues 1,390 883 1,764 — — 4,037 Purchased oil and gas sales — — 394 4 — 398 Midstream service affiliate revenues — — — 145 (145) — 1,390 883 2,158 149 (145) 4,435 Operating Expenses: Lease operating expenses 424 305 400 — (2) 1,127 Gathering, processing, and transmission 38 50 291 38 (143) 274 Purchased oil and gas costs — — 354 3 — 357 Taxes other than income — — 108 15 — 123 Exploration 63 28 168 — 15 274 Depreciation, depletion, and amortization 601 380 779 12 — 1,772 Asset retirement obligation accretion — 73 32 4 — 109 Impairments 529 7 3,963 2 — 4,501 1,655 843 6,095 74 (130) 8,537 Operating Income (Loss) $ (265) $ 40 $ (3,937) $ 75 $ (15) (4,102) Other Income (Expense): Gain on divestitures, net 32 Derivative instrument losses, net (223) Other 64 General and administrative (290) Transaction, reorganization, and separation (54) Financing costs, net (267) Loss Before Income Taxes $ (4,840) Total Assets (3) $ 3,003 $ 2,220 $ 5,540 $ 1,786 $ 197 $ 12,746 Net Property and Equipment $ 1,955 $ 1,773 $ 4,760 $ 196 $ 135 $ 8,819 Additions to Net Property and Equipment $ 454 $ 215 $ 345 $ 12 $ 136 $ 1,162 (1) Includes revenue from non-customers for the years ended December 31, 2022, 2021, and 2020 of: For the Year Ended December 31, 2022 2021 2020 (In millions) Oil $ 989 $ 420 $ 95 Natural gas 117 47 14 Natural gas liquids 2 2 — (2) Includes noncontrolling interests in Egypt and Altus Midstream. (3) Intercompany balances are excluded from total assets. |
SUPPLEMENTAL OIL AND GAS DISCLO
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) | SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) Oil and Gas Operations The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2022 Oil and gas production revenues $ 3,952 $ 3,521 $ 1,558 $ — $ 9,031 Operating cost: Depreciation, depletion, and amortization (2) 508 390 232 — 1,130 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 506 526 404 — 1,436 Gathering, processing, and transmission 304 22 43 — 369 Exploration expenses 24 84 35 3 146 Production taxes (3) 252 — — — 252 Income tax 488 1,100 495 — 2,083 2,116 2,122 1,291 3 5,532 Results of operations $ 1,836 $ 1,399 $ 267 $ (3) $ 3,499 2021 Oil and gas production revenues $ 3,280 $ 2,085 $ 1,136 $ — $ 6,501 Operating cost: Depreciation, depletion, and amortization (2) 511 477 267 — 1,255 Asset retirement obligation accretion 30 — 79 — 109 Lease operating expenses 391 469 383 — 1,243 Gathering, processing, and transmission 309 12 39 — 360 Exploration expenses 28 63 34 2 127 Production taxes (3) 188 — — — 188 Income tax 383 479 134 — 996 1,840 1,500 936 2 4,278 Results of operations $ 1,440 $ 585 $ 200 $ (2) $ 2,223 2020 Oil and gas production revenues $ 1,764 $ 1,390 $ 883 $ — $ 4,037 Operating cost: Depreciation, depletion, and amortization (2) 726 540 377 — 1,643 Asset retirement obligation accretion 32 — 73 — 105 Lease operating expenses 400 424 305 — 1,129 Gathering, processing, and transmission 291 38 50 — 379 Exploration expenses 168 63 28 15 274 Impairments related to oil and gas properties 3,938 374 7 — 4,319 Production taxes (3) 106 — — — 106 Income tax (818) (22) 17 — (823) 4,843 1,417 857 15 7,132 Results of operations $ (3,079) $ (27) $ 26 $ (15) $ (3,095) (1) Includes noncontrolling interests in Egypt. (2) Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 18—Business Segment Information . (3) Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 18—Business Segment Information . Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United Egypt (2) North Sea Other Total (2) (In millions) 2022 Acquisitions: Proved $ 19 $ 3 $ — $ — $ 22 Unproved 28 — — — 28 Exploration 4 169 61 3 237 Development 775 568 (57) — 1,286 Costs incurred (1) $ 826 $ 740 $ 4 $ 3 $ 1,573 (1) Includes capitalized interest, asset retirement costs: Capitalized interest $ — $ — $ 1 $ — $ 1 Asset retirement costs 76 — (215) — (139) 2021 Acquisitions: Proved $ — $ (157) $ — $ — $ (157) Unproved 9 20 — — 29 Exploration 6 86 39 30 161 Development 545 404 135 1 1,085 Costs incurred (1) $ 560 $ 353 $ 174 $ 31 $ 1,118 (1) Includes capitalized interest and asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ — $ — $ — Asset retirement costs 130 — 19 — 149 Egypt PSC modernization impacts - Proved and Unproved — (145) — — (145) 2020 Acquisitions: Proved $ — $ 7 $ — $ — $ 7 Unproved 4 — — — 4 Exploration 8 102 68 150 328 Development 332 378 162 — 872 Costs incurred (1) $ 344 $ 487 $ 230 $ 150 $ 1,211 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ — $ 3 $ 3 Asset retirement costs 9 — 29 — 38 (2) Includes a noncontrolling interest in Egypt. In 2021, in connection with Apache’s agreement to enter into a new merged concession agreement with EGPC, as referenced in Note 1—Summary of Significant Accounting Policies , the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments. Capitalized Costs The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities: United Egypt (1) North Other Total (1) (In millions) 2022 Proved properties $ 18,990 $ 13,014 $ 8,945 $ — $ 40,949 Unproved properties 208 77 11 — 296 19,198 13,091 8,956 — 41,245 Accumulated DD&A (14,846) (11,157) (7,573) — (33,576) $ 4,352 $ 1,934 $ 1,383 $ — $ 7,669 2021 Proved properties $ 18,732 $ 12,373 $ 8,954 $ — $ 40,059 Unproved properties 319 63 33 — 415 19,051 12,436 8,987 — 40,474 Accumulated DD&A (14,814) (10,767) (7,345) — (32,926) $ 4,237 $ 1,669 $ 1,642 $ — $ 7,548 Oil and Gas Reserve Information Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Crude Oil and Condensate United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2019 278,145 103,573 101,712 483,430 December 31, 2020 206,936 95,981 86,566 389,483 December 31, 2021 180,968 106,646 77,073 364,687 December 31, 2022 168,817 108,050 82,580 359,447 Proved undeveloped reserves: December 31, 2019 46,716 10,831 10,049 67,596 December 31, 2020 25,516 11,228 7,273 44,017 December 31, 2021 18,168 11,003 5,757 34,928 December 31, 2022 16,221 8,557 2,873 27,651 Total proved reserves: Balance December 31, 2019 324,861 114,404 111,761 551,026 Extensions, discoveries and other additions 17,858 17,855 5,275 40,988 Revisions of previous estimates (69,247) 2,541 (4,756) (71,462) Production (32,299) (27,591) (18,441) (78,331) Sales of minerals in-place (8,721) — — (8,721) Balance December 31, 2020 232,452 107,209 93,839 433,500 Extensions, discoveries and other additions 17,869 13,390 2,288 33,547 Purchases of minerals in-place 126 — — 126 Revisions of previous estimates (4,479) 22,727 (60) 18,188 Production (27,450) (25,677) (13,237) (66,364) Sales of minerals in-place (19,382) — — (19,382) Balance December 31, 2021 199,136 117,649 82,830 399,615 Extensions, discoveries and other additions 9,776 7,580 2,616 19,972 Purchases of minerals in-place 522 — — 522 Revisions of previous estimates 7,170 22,433 11,898 41,501 Production (24,141) (31,055) (11,891) (67,087) Sales of minerals in-place (7,425) — — (7,425) Balance December 31, 2022 185,038 116,607 85,453 387,098 (1) Includes proved reserves of 62 MMbbls, 39 MMbbls, 36 MMbbls, and 38 MMbbls as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2019 158,794 667 2,317 161,778 December 31, 2020 150,599 716 2,053 153,368 December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 152,999 — 2,230 155,229 Proved undeveloped reserves: December 31, 2019 23,569 90 660 24,319 December 31, 2020 15,141 126 320 15,587 December 31, 2021 16,380 30 275 16,685 December 31, 2022 15,398 — 76 15,474 Total proved reserves: Balance December 31, 2019 182,363 757 2,977 186,097 Extensions, discoveries and other additions 11,435 97 312 11,844 Revisions of previous estimates (469) 264 (207) (412) Production (27,133) (276) (709) (28,118) Sales of minerals in-place (456) — — (456) Balance December 31, 2020 165,740 842 2,373 168,955 Extensions, discoveries and other additions 21,055 7 81 21,143 Purchases of minerals in-place 191 — — 191 Revisions of previous estimates 22,724 (180) 318 22,862 Production (24,175) (193) (438) (24,806) Sales of minerals in-place (4,983) — — (4,983) Balance December 31, 2021 180,552 476 2,334 183,362 Extensions, discoveries and other additions 5,456 — 45 5,501 Purchases of minerals in-place 233 — — 233 Revisions of previous estimates 10,355 (407) 333 10,281 Production (21,859) (69) (406) (22,334) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 168,397 — 2,306 170,703 (1) Includes proved reserves of 159 Mbbls, 281 Mbbls, and 252 Mbbls as of December 31, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2019 945,938 433,382 106,329 1,485,649 December 31, 2020 1,052,756 409,035 68,159 1,529,950 December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,128,066 399,502 66,292 1,593,860 Proved undeveloped reserves: December 31, 2019 115,040 24,704 16,604 156,348 December 31, 2020 76,504 12,572 8,341 97,417 December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 188,976 1,068 2,304 192,348 Total proved reserves: Balance December 31, 2019 1,060,978 458,086 122,933 1,641,997 Extensions, discoveries and other additions 60,965 83,718 8,140 152,823 Revisions of previous estimates 215,166 (19,849) (33,541) 161,776 Production (205,594) (100,348) (21,032) (326,974) Sales of minerals in-place (2,255) — — (2,255) Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 Extensions, discoveries and other additions 227,684 50,209 3,684 281,577 Purchases of minerals in-place 839 — — 839 Revisions of previous estimates 279,610 99,143 17,171 395,924 Production (192,523) (96,234) (14,076) (302,833) Sales of minerals in-place (22,968) — — (22,968) Balance December 31, 2021 1,421,902 474,725 83,279 1,979,906 Extensions, discoveries and other additions 38,157 10,191 1,643 49,991 Purchases of minerals in-place 1,592 — — 1,592 Revisions of previous estimates 96,381 45,725 (3,431) 138,675 Production (167,580) (130,071) (12,895) (310,546) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,317,042 400,570 68,596 1,786,208 (1) Includes proved reserves of 224 Bcf, 158 Bcf, 141 Bcf, and 153 Bcf as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2019 594,595 176,470 121,751 892,816 December 31, 2020 532,994 164,870 99,979 797,843 December 31, 2021 551,384 184,563 91,825 827,772 December 31, 2022 509,827 174,633 95,859 780,319 Proved undeveloped reserves: December 31, 2019 89,458 15,038 13,476 117,972 December 31, 2020 53,408 13,449 8,983 75,840 December 31, 2021 65,288 12,683 7,219 85,190 December 31, 2022 63,115 8,735 3,333 75,183 Total proved reserves: Balance December 31, 2019 684,053 191,508 135,227 1,010,788 Extensions, discoveries and other additions 39,454 31,905 6,944 78,303 Revisions of previous estimates (33,854) (502) (10,554) (44,910) Production (93,698) (44,592) (22,655) (160,945) Sales of minerals in-place (9,553) — — (9,553) Balance December 31, 2020 586,402 178,319 108,962 873,683 Extensions, discoveries and other additions 76,871 21,765 2,983 101,619 Purchases of minerals in-place 457 — — 457 Revisions of previous estimates 64,847 39,071 3,120 107,038 Production (83,712) (41,909) (16,021) (141,642) Sales of minerals in-place (28,193) — — (28,193) Balance December 31, 2021 616,672 197,246 99,044 912,962 Extensions, discoveries and other additions 21,592 9,278 2,935 33,805 Purchases of minerals in-place 1,020 — — 1,020 Revisions of previous estimates 33,588 29,647 11,659 74,894 Production (73,930) (52,803) (14,446) (141,179) Sales of minerals in-place (26,000) — — (26,000) Balance December 31, 2022 572,942 183,368 99,192 855,502 (1) Includes total proved reserves of 99 MMboe, 66 MMboe, 59 MMboe, and 64 MMboe as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. During 2022, the Company added approximately 34 MMboe from extensions, discoveries, and other additions. The Company recorded 22 MMboe of exploration and development adds in the U.S., comprising 9 MMboe in the Permian Basin, 8 MMboe in the Texas Gulf Coast, and 5 MMboe in the Delaware Basin. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 12 MMboe of exploration and development adds, with Egypt contributing 9 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 3 MMboe from the North Sea. The Company had combined upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with Egypt accounting for an increase of 43 MMboe, primarily the result of PSC modernization in Egypt. The North Sea contributed 9 MMboe of upward revisions from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 1 MMboe of proved reserves and sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets. During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the new merged concession agreement in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets. As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt. During 2020, the Company added approximately 78 MMboe from extensions, discoveries, and other additions. The Company recorded 39 MMboe of exploration and development adds in the U.S., primarily in the Southern Midland Basin (26 MMboe) associated with the Wolfcamp and Spraberry drilling programs and the remainder in the Delaware Basin and Austin Chalk. The international operations contributed 39 MMboe of exploration and development adds during 2020, with Egypt contributing 32 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and Umbarka Area concessions. The North Sea contributed 7 MMboe from drilling success, primarily in the Beryl Field. The Company had combined downward revisions of previously estimated reserves of 45 MMboe. Downward revisions related to changes in product prices accounted for 70 MMboe, engineering and performance upward revisions accounted for 27 MMboe, and downward interest revisions accounted for 2 MMboe. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge. Approximately 11 percent of the Company’s year-end 2022 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.” Future Net Cash Flows Future cash inflows as of December 31, 2022, 2021, and 2020 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs. The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2022, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. United Egypt (1) North Total (1) (In millions) 2022 Cash inflows $ 29,490 $ 12,819 $ 10,147 $ 52,456 Production costs (10,221) (2,086) (3,241) (15,548) Development costs (1,598) (1,471) (2,297) (5,366) Income tax expense (1,389) (2,729) (2,631) (6,749) Net cash flows 16,282 6,533 1,978 24,793 10 percent discount rate (6,422) (1,400) (204) (8,026) Discounted future net cash flows (2) $ 9,860 $ 5,133 $ 1,774 $ 16,767 2021 Cash inflows $ 22,852 $ 9,337 $ 6,832 $ 39,021 Production costs (8,323) (1,712) (2,343) (12,378) Development costs (1,632) (1,402) (2,533) (5,567) Income tax expense (134) (1,887) (768) (2,789) Net cash flows 12,763 4,336 1,188 18,287 10 percent discount rate (5,294) (983) 350 (5,927) Discounted future net cash flows (2) $ 7,469 $ 3,353 $ 1,538 $ 12,360 2020 Cash inflows $ 12,537 $ 5,560 $ 4,122 $ 22,219 Production costs (6,244) (1,704) (2,388) (10,336) Development costs (1,555) (633) (2,448) (4,636) Income tax expense — (1,096) 316 (780) Net cash flows 4,738 2,127 (398) 6,467 10 percent discount rate (1,829) (437) 1,111 (1,155) Discounted future net cash flows (2) $ 2,909 $ 1,690 $ 713 $ 5,312 (1) Includes discounted future net cash flows of approximately $2.5 billion , $1.6 billion, and $563 million as of December 31, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $16.1 billion , $14.9 billion, and $7.1 billion as of December 31, 2022, 2021, and 2020, respectively. The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2022 2021 2020 (In millions) Sales, net of production costs $ (6,970) $ (4,707) $ (2,422) Net change in prices and production costs 8,627 9,376 (5,753) Discoveries and improved recovery, net of related costs 1,132 1,749 751 Change in future development costs (347) (839) 20 Previously estimated development costs incurred during the period 669 545 576 Revision of quantities 2,621 1,983 (418) Purchases of minerals in-place 17 1 — Accretion of discount 1,489 626 1,236 Change in income taxes (2,371) (1,583) 1,533 Sales of minerals in-place (363) (116) (104) Change in production rates and other (97) 13 11 $ 4,407 $ 7,048 $ (4,570) |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail. 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. Noncontrolling interests represent outside ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. In conjunction with the ratification of a new merged concession agreement with the Egyptian General Petroleum Corporation (EGPC) in December 2021, Apache modified partnership agreements for certain consolidated subsidiaries. Apache subsequently determined that one of its limited partnership subsidiaries, which has control over Apache’s Egyptian operations, qualified as a variable interest entity (VIE) under GAAP. Apache continues to consolidate this limited partnership subsidiary because the Company has concluded that it has a controlling financial interest in the Egyptian operations and was determined to be the primary beneficiary of the VIE. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a minority participation in the remaining two-thirds of its consolidated Egypt oil and gas business as a noncontrolling interest. Refer to Note 2—Transactions with Parent Affiliate for detail regarding APA’s noncontrolling interest. All noncontrolling interests are reflected as a separate 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, 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 Apache consolidated because a wholly owned subsidiary of Apache had a controlling financial interest and was determined to be the primary beneficiary. Additionally, the assets of ALTM could only be used to settle obligations of ALTM. There was no recourse to the Company for ALTM’s liabilities. 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 3—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. 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 7—Equity Method Interests 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 3—Acquisitions and Divestitures ), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests ), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation ), the estimate of income taxes (refer to Note 11—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 12—Commitments and Contingencies ), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited) ). |
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 Upstream The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to provide flexibility to fulfill sales obligations and commitments. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title. The Company’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer. On December 27, 2021, the Company announced the ratification of a new merged concession agreement (MCA) with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. For all periods presented, Sinopec has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a minority participation in the remaining two-thirds of its consolidated Egypt oil and gas business as a noncontrolling interest. Refer to Note 18—Business Segment Information for a disaggregation of revenue by product and reporting segment. Altus Midstream Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which were fully eliminated upon consolidation. Payment Terms and Contract Balances Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.3 billion at each of December 31, 2022 and 2021. 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. |
Cash and Cash Equivalents | Cash and Cash EquivalentsThe Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. |
Accounts Receivable and Allowance for Credit Losses | Accounts Receivable and Allowance for Credit LossesAccounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. |
Receivable from / Payable to APA | Receivable from / Payable to APAReceivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Cash will be transferred to Apache or paid to APA over time in order to manage affiliate balances for cash management purposes. |
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 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 | 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. The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2020. The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2022 2021 2020 (In millions) Proved properties: U.S. $ — $ — $ 3,938 Egypt — — 374 North Sea — — 7 Total proved properties $ — $ — $ 4,319 Unproved properties: U.S. $ 20 $ 22 $ 92 Egypt 4 8 8 North Sea — 1 1 Total unproved properties $ 24 $ 31 $ 101 Proved properties impaired had an aggregate fair value as of the most recent date of impairment of $1.9 billion for 2020. |
Gathering, Processing, and Transmission (GPT) Facilities | Gathering, Processing, and Transmission (GPT) Facilities GPT facilities totaled $449 million and $673 million at December 31, 2022 and 2021, respectively, with accumulated depreciation for these assets totaling $367 million and $386 million for the respective periods. As a result of the BCP Business Combination, the Company deconsolidated $183 million of Altus GPT net assets on February 22, 2022. 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. |
Asset Retirement Costs and Obligations | Asset Retirement Costs and Obligations The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets. |
Capitalized Interest | Capitalized Interest |
Goodwill | Goodwill Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense. |
Equity Method Interests | Equity Method Interests The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company. |
Commitments and Contingencies | Commitments and ContingenciesAccruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. |
Income Taxes | Income Taxes Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. Apache is a directly owned subsidiary of APA Corporation and is included in APA Corporation and Subsidiaries’ U.S. Federal income tax return. The Company’s financial statements recognize the current and deferred income tax consequences that result from Apache’s activities during the current period pursuant to the provisions of ASC Topic 740 “Income Taxes” as if the Company were a separate taxpayer rather than a member of APA Corporation’s consolidated income tax return group. |
Stock-Based Compensation | Stock-Based Compensation Prior to consummation of the Holding Company Reorganization, Apache granted various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on APA’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s stock-based compensation plans, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock . |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Schedule of Asset Impairments Recorded in Connection with Fair Value Assessment | The following table presents a summary of asset impairments recorded in connection with fair value assessments: For the Year Ended December 31, 2022 2021 2020 (In millions) Oil and gas proved property $ — $ — $ 4,319 Gathering, processing, and transmission facilities — — 68 Equity method interests — 160 — Goodwill — — 87 Inventory and other — 48 27 Total Impairments $ — $ 208 $ 4,501 |
Schedule of Allowance for Doubtful Accounts | The following table presents changes to the Company’s allowance for credit loss: For the Year Ended December 31, 2022 2021 2020 (In millions) Allowance for credit loss at beginning of year $ 109 $ 95 $ 88 Additional provisions for the year 9 19 7 Uncollectible accounts written off, net of recoveries (1) (5) — Allowance for credit loss at end of year $ 117 $ 109 $ 95 |
Schedule of Non-cash Impairments of Proved and Unproved Properties | The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties: For the Year Ended December 31, 2022 2021 2020 (In millions) Proved properties: U.S. $ — $ — $ 3,938 Egypt — — 374 North Sea — — 7 Total proved properties $ — $ — $ 4,319 Unproved properties: U.S. $ 20 $ 22 $ 92 Egypt 4 8 8 North Sea — 1 1 Total unproved properties $ 24 $ 31 $ 101 |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Business Combinations [Abstract] | |
Schedule Of Components Of Deconsolidation | A summary of components of the gain, including the ALTM balance sheet amounts deconsolidated at the time of close, is included below: As of February 22, 2022 (In millions) Fair value of Kinetik Class A Common Stock held by Company $ 802 ASSETS: Cash and cash equivalents $ 143 Other current assets 29 Property and equipment, net 184 Equity method interests 1,367 Other noncurrent assets 12 Total assets deconsolidated $ 1,735 LIABILITIES: Current liabilities $ 3 Long-term debt 657 Other noncurrent liabilities 168 Total liabilities deconsolidated $ 828 NONCONTROLLING INTERESTS: Redeemable noncontrolling interest preferred unit limited partners $ 642 Noncontrolling interest-Altus 72 Total noncontrolling interests deconsolidated $ 714 Net effect of deconsolidating balance sheet $ (193) Gain on deconsolidation of ALTM $ 609 |
CAPITALIZED EXPLORATORY WELL _2
CAPITALIZED EXPLORATORY WELL COSTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Exploratory Well Costs, Roll Forward | The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2022, 2021, and 2020. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year. For the Year Ended December 31, 2022 2021 2020 (In millions) Capitalized well costs at beginning of year $ 46 $ 197 $ 141 Additions pending determination of proved reserves 138 62 226 Divestitures and other — (163) (38) Reclassifications to proved properties (110) (40) (56) Charged to exploration expense (24) (10) (76) Capitalized well costs at end of year $ 50 $ 46 $ 197 |
Schedule of Aging of Capitalized Exploratory Well Costs | The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31: 2022 2021 2020 (In millions) Exploratory well costs capitalized for a period of one year or less $ 34 $ 13 $ 184 Exploratory well costs capitalized for a period greater than one year 16 33 13 Capitalized well costs at end of year $ 50 $ 46 $ 197 Number of projects with exploratory well costs capitalized for a period greater than one year 10 9 5 |
Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year | The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2022, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed: Total 2021 2020 2019 (In millions) Egypt $ 14 $ 5 $ — $ 9 North Sea 2 2 — — $ 16 $ 7 $ — $ 9 |
DERIVATIVE INSTRUMENTS AND HE_2
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
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 (Level 1) Significant Other Inputs (Level 2) Significant Unobservable Inputs Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2022 Assets: Commodity derivative instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity derivative instruments $ — $ — $ — $ — $ — $ — December 31, 2021 Liabilities: Commodity derivative instruments $ — $ 10 $ — $ 10 $ — $ 10 Pipeline capacity embedded derivatives — 46 — 46 — 46 Preferred Units embedded derivative — — 57 57 — 57 (1) Derivative fair values were 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 (Level 1) Significant Other Inputs (Level 2) Significant Unobservable Inputs Total Fair Value Netting (1) Carrying Amount (In millions) December 31, 2022 Assets: Commodity derivative instruments $ — $ — $ — $ — $ — $ — Liabilities: Commodity derivative instruments $ — $ — $ — $ — $ — $ — December 31, 2021 Liabilities: Commodity derivative instruments $ — $ 10 $ — $ 10 $ — $ 10 Pipeline capacity embedded derivatives — 46 — 46 — 46 Preferred Units embedded derivative — — 57 57 — 57 (1) Derivative fair values were 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 were as follows: For the Year Ended December 31, 2022 2021 (In millions) Current Assets: Other current assets $ — $ — Other Assets: Deferred charges and other — — Total derivative assets $ — $ — Current Liabilities: Other current liabilities $ — $ 4 Deferred Credits and Other Noncurrent Liabilities: Other — 109 Total derivative liabilities $ — $ 113 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 Year Ended December 31, 2022 2021 2020 (In millions) Realized: Commodity derivative instruments $ (72) $ 25 $ (135) Foreign currency derivative instruments (13) — (1) Realized gain (loss), net (85) 25 (136) Unrealized: Commodity derivative instruments 9 (20) 11 Pipeline capacity embedded derivatives — 7 (61) Foreign currency derivative instruments — — (1) Preferred Units embedded derivative (31) 82 (36) Unrealized gain (loss), net (22) 69 (87) Derivative instrument gains (losses), net $ (107) $ 94 $ (223) |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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 as of December 31: 2022 2021 (In millions) Inventories $ 425 $ 438 Drilling advances 64 55 Prepaid assets and other 54 56 Current decommissioning security for sold Gulf of Mexico assets 450 100 Total Other current assets $ 993 $ 649 |
EQUITY METHOD INTERESTS (Tables
EQUITY METHOD INTERESTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Summary of Equity Method Investment Information | The following table presents the activity in the Company’s equity method interest in Kinetik for the year ended December 31, 2022: Kinetik Holdings Inc (In millions) Balance at December 31, 2021 $ — Initial interest upon closing the BCP Business Combination 802 Sale of Class A shares (250) Paid-in-kind dividend 40 Fair value adjustments 32 Balance at December 31, 2022 $ 624 Interest December 31, 2021 (In millions) Gulf Coast Express Pipeline LLC 16.0 % $ 274 EPIC Crude Holdings, LP 15.0 % — Permian Highway Pipeline LLC 26.7 % 630 Shin Oak Pipeline (Breviloba, LLC) 33.0 % 461 Total Altus equity method interests $ 1,365 The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2022 and 2021: Gulf Coast Express Pipeline LLC EPIC Crude Holdings, LP Permian Highway Pipeline LLC Breviloba, LLC Total (In millions) Balance at December 31, 2020 $ 284 $ 176 $ 615 $ 480 $ 1,555 Capital contributions — 2 26 — 28 Distributions (50) — (74) (49) (173) Equity income (loss), net 40 (19) 63 30 114 Accumulated other comprehensive loss — 1 — — 1 Impairment (1) — (160) — — (160) Balance at December 31, 2021 274 — 630 461 1,365 Capital contributions — 2 — — 2 Distributions (5) — (9) (7) (21) Equity income (loss), net 8 (2) 10 5 21 Deconsolidation of Altus (277) — (631) (459) (1,367) Balance at December 31, 2022 $ — $ — $ — $ — $ — (1) Prior to the deconsolidation of Altus on February 22, 2022, the Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies for further details on this impairment charge. |
OTHER CURRENT LIABILITIES (Tabl
OTHER CURRENT LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Payables and Accruals [Abstract] | |
Schedule of Detail of Other Current Liabilities | The following table provides detail of the Company’s other current liabilities as of December 31: 2022 2021 (In millions) Accrued operating expenses $ 139 $ 129 Accrued exploration and development 300 206 Accrued compensation and benefits 514 292 Accrued interest 96 107 Accrued income taxes 90 28 Current asset retirement obligation 55 41 Current operating lease liability 167 99 Current decommissioning contingency for sold Gulf of Mexico properties 450 100 Other 238 168 Total Other current liabilities $ 2,049 $ 1,170 |
ASSET RETIREMENT OBLIGATION (Ta
ASSET RETIREMENT OBLIGATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Changes to Asset Retirement Obligation | The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2022 and 2021: For the Year Ended December 31, 2022 2021 (In millions) Asset retirement obligation at beginning of the year $ 2,130 $ 1,944 Liabilities incurred 4 3 Liabilities divested (73) (44) Liabilities settled (39) (32) Accretion expense 117 113 Revisions in estimated liabilities (148) 146 Asset retirement obligation at end of the year 1,991 2,130 Less current portion (55) (41) Asset retirement obligation, long-term $ 1,936 $ 2,089 |
DEBT AND FINANCING COSTS (Table
DEBT AND FINANCING COSTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The following table presents the carrying value of the Company’s debt as of December 31, 2022 and 2021: December 31, 2022 2021 (In millions) 3.25% notes due 2022 (1) $ — $ 213 2.625% notes due 2023 (2) — 123 4.625% notes due 2025 (3) 51 500 7.7% notes due 2026 78 79 7.95% notes due 2026 132 133 4.875% due 2027 (3) 108 378 4.375% notes due 2028 (3) 325 703 7.75% notes due 2029 (3)(4) 235 235 4.25% notes due 2030 (3) 579 580 6.0% notes due 2037 (3) 443 443 5.1% notes due 2040 (3) 1,333 1,333 5.25% notes due 2042 (3) 399 399 4.75% notes due 2043 (3) 428 428 4.25% notes due 2044 (3) 221 221 7.375% debentures due 2047 150 150 5.35% notes due 2049 (3) 387 387 7.625% debentures due 2096 39 39 Notes and debentures before unamortized discount and debt issuance costs (5) 4,908 6,344 Altus credit facility (6) — 657 Syndicated credit facilities (6)(7) — 542 Finance lease obligations 34 36 Unamortized discount (27) (30) Debt issuance costs (28) (39) Total debt 4,887 7,510 Current maturities (2) (215) Long-term debt $ 4,885 $ 7,295 (1) On January 18, 2022, Apache redeemed the 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. (2) On October 17, 2022, Apache redeemed the 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. (3) These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable. (4) Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache. (5) The fair values of Apache’s notes and debentures were $4.2 billion and $7.1 billion as of December 31, 2022 and 2021, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (6) The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates. (7) Although Apache had no borrowings under APA’s syndicated credit facilities as of December 31, 2022, Apache currently is a guarantor of obligations under those facilities. |
Schedule of Long Term Debt by Maturity | Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2022 are as follows: (In millions) 2023 $ — 2024 — 2025 51 2026 210 2027 108 Thereafter 4,539 Notes and debentures, excluding discounts and debt issuance costs $ 4,908 |
Schedule of Components of Financing Costs, Net | The following table presents the components of the Company’s financing costs, net: For the Year Ended December 31, 2022 2021 2020 (In millions) Interest expense $ 312 $ 419 $ 438 Amortization of debt issuance costs 7 8 8 Capitalized interest (1) — (12) Loss (gain) on extinguishment of debt 67 104 (160) Interest income (9) (8) (7) Interest income from APA Corporation, net (63) (51) — Financing costs, net $ 313 $ 472 $ 267 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income (Loss) Before Income Taxes | Income (loss) before income taxes was composed of the following: For the Year Ended December 31, 2022 2021 2020 (In millions) U.S. $ 2,656 $ 689 $ (4,581) Foreign 3,218 1,291 (259) Total $ 5,874 $ 1,980 $ (4,840) |
Schedule of Total Provision for Income Taxes | The total income tax provision consisted of the following: For the Year Ended December 31, 2022 2021 2020 (In millions) Current income taxes: Federal $ 1 $ 16 $ (2) State 11 — — Foreign 1,495 636 178 1,507 652 176 Deferred income taxes: Federal — — — Foreign 145 (74) (112) 145 (74) (112) Total $ 1,652 $ 578 $ 64 |
Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense | A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below: For the Year Ended December 31, 2022 2021 2020 (In millions) Income tax expense (benefit) at U.S. statutory rate $ 1,234 $ 416 $ (1,016) State income tax, less federal effect (1) 9 — — Taxes related to foreign operations 774 300 97 Tax credits (4) (10) (13) Net change in tax contingencies 1 16 1 Goodwill impairment — — 35 Valuation allowances (1) (705) (111) 965 Tax adjustments attributable to BCP Business Combination 126 — — Remeasurement of U.K. deferred tax liability 208 — — Tax attributable to Altus Preferred Unit limited partners — (34) (16) All other, net 9 1 11 $ 1,652 $ 578 $ 64 (1) The change in state valuation allowance is included as a component of state income tax. |
Schedule of Net Deferred Tax Liability | The net deferred income tax liability consisted of the following as of December 31: 2022 2021 (In millions) Deferred tax assets: U.S. and state net operating losses $ 2,035 $ 2,494 Capital losses 357 647 Tax credits and other tax incentives 26 24 Foreign tax credits 2,241 2,241 Accrued expenses and liabilities 145 152 Asset retirement obligation 672 712 Property and equipment — 3 Investment in Altus Midstream LP — 64 Net interest expense limitation 55 135 Lease liability 113 81 Decommissioning contingency for sold Gulf of Mexico properties 275 263 Other — 1 Total deferred tax assets 5,919 6,817 Valuation allowance (4,831) (5,875) Net deferred tax assets 1,088 942 Deferred tax liabilities: Equity investments 1 2 Property and equipment 1,014 748 Right-of-use asset 110 77 Decommissioning security for sold Gulf of Mexico properties 148 164 Other 90 86 Total deferred tax liabilities 1,363 1,077 Net deferred income tax liability $ 275 $ 135 Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows: 2022 2021 (In millions) Assets: Deferred charges and other $ 39 $ 13 Liabilities: Income taxes 314 148 Net deferred income tax liability $ 275 $ 135 |
Schedule of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses | 2022 2021 2020 (In millions) Balance at beginning of year $ 5,875 $ 5,991 $ 4,959 State (1) (111) 1 67 U.S. (706) (112) 960 Foreign (227) (5) 5 Balance at end of year $ 4,831 $ 5,875 $ 5,991 (1) Reported as a component of state income taxes. |
Schedule of Net Operating Losses | On December 31, 2022, the Company had net operating losses as follows: Amount Expiration (In millions) U.S. $ 7,968 2027 - Indefinite State 6,505 Various |
Schedule of Foreign Tax Credit Carryforward | On December 31, 2022, the Company had foreign tax credits as follows: Amount Expiration (In millions) Foreign tax credits $ 2,241 2025-2026 |
Schedule of Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 2022 2021 2020 (In millions) Balance at beginning of year $ 116 $ 93 $ 82 Additions based on tax positions related to prior year — 16 — Additions based on tax positions related to the current year — 7 11 Reductions for tax positions of prior years (27) — — Balance at end of year $ 89 $ 116 $ 93 |
Schedule of Key Jurisdictions of Company's Earliest Open Tax Years | Apache’s earliest open tax years in its key jurisdictions are as follows: Jurisdiction U.S. 2014 Egypt 2005 U.K. 2021 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Lease Cost | The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2022: Operating Leases Finance Lease Weighted average remaining lease term 2.5 years 10.7 years Weighted average discount rate 3.7 % 4.4 % |
Schedule of Operating Lease, Liability, Maturity | At December 31, 2022, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2023 $ 174 $ 3 $ 222 2024 102 3 183 2025 14 4 163 2026 6 4 1,951 2027 6 4 133 Thereafter 11 27 333 Total future minimum payments 313 45 $ 2,985 Less: imputed interest (14) (11) N/A Total lease liabilities 299 34 N/A Current portion 167 2 N/A Non-current portion $ 132 $ 32 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $183 million, $194 million, and $120 million in 2022, 2021, and 2020, respectively. |
Schedule of Finance Lease, Liability, Maturity | At December 31, 2022, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2023 $ 174 $ 3 $ 222 2024 102 3 183 2025 14 4 163 2026 6 4 1,951 2027 6 4 133 Thereafter 11 27 333 Total future minimum payments 313 45 $ 2,985 Less: imputed interest (14) (11) N/A Total lease liabilities 299 34 N/A Current portion 167 2 N/A Non-current portion $ 132 $ 32 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $183 million, $194 million, and $120 million in 2022, 2021, and 2020, respectively. |
Schedule of Long-term Purchase Commitment | At December 31, 2022, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows: Net Minimum Commitments (1) Operating Leases (2) Finance Lease (3) Purchase Obligations (4)(5) (In millions) 2023 $ 174 $ 3 $ 222 2024 102 3 183 2025 14 4 163 2026 6 4 1,951 2027 6 4 133 Thereafter 11 27 333 Total future minimum payments 313 45 $ 2,985 Less: imputed interest (14) (11) N/A Total lease liabilities 299 34 N/A Current portion 167 2 N/A Non-current portion $ 132 $ 32 N/A (1) Excludes commitments for jointly owned fields and facilities for which the Company is not the operator. (2) Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense. (3) Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building. (4) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $183 million, $194 million, and $120 million in 2022, 2021, and 2020, respectively. |
RETIREMENT AND DEFERRED COMPE_2
RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
Schedule of Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans | The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2022, 2021, and 2020, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans. 2022 2021 2020 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Change in Projected Benefit Obligation Projected benefit obligation at beginning of year $ 211 $ 20 $ 233 $ 20 $ 199 $ 20 Service cost 2 1 3 1 3 1 Interest cost 3 — 3 — 4 — Foreign currency exchange rates (21) — (2) — 8 — Actuarial losses (gains) (79) (5) (5) 1 30 1 Plan settlements — — (17) — — — Benefits paid (8) (3) (4) (4) (11) (4) Retiree contributions — 2 — 2 — 2 Projected benefit obligation at end of year 108 15 211 20 233 20 Change in Plan Assets Fair value of plan assets at beginning of year 254 — 262 — 228 — Actual return (loss) on plan assets (87) — 11 — 31 — Foreign currency exchange rates (26) — (3) — 9 — Employer contributions 4 2 5 2 5 2 Plan settlements — — (17) — — — Benefits paid (8) (4) (4) (4) (11) (4) Retiree contributions — 2 — 2 — 2 Fair value of plan assets at end of year 137 — 254 — 262 — Funded status at end of year $ 29 $ (15) $ 43 $ (20) $ 29 $ (20) Amounts recognized in Consolidated Balance Sheet Current liability $ — $ (2) $ — $ (2) $ — $ (2) Non-current asset (liability) 29 (13) 43 (18) 29 (18) $ 29 $ (15) $ 43 $ (20) $ 29 $ (20) Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) Accumulated gain (loss) $ (10) $ 18 $ 1 $ 14 $ (11) $ 16 Weighted Average Assumptions used as of December 31 Discount rate 5.00 % 5.29 % 1.80 % 2.57 % 1.40 % 2.06 % Salary increases 4.70 % N/A 4.90 % N/A 4.50 % N/A Expected return on assets 4.70 % N/A 1.90 % N/A 1.50 % N/A Healthcare cost trend Initial N/A 6.50 % N/A 6.25 % N/A 6.00 % Ultimate in 2028 N/A 5.25 % N/A 5.00 % N/A 5.00 % |
Schedule of Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset | A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below: Target Percentage of 2022 2022 2021 Asset Category Equity securities: Overseas quoted equities 14 % 15 % 15 % Total equity securities 14 % 15 % 15 % Debt securities: U.K. government bonds 52 % 52 % 54 % U.K. corporate bonds 32 % 32 % 25 % Total debt securities 84 % 84 % 79 % Cash 2 % 1 % 6 % Total 100 % 100 % 100 % |
Schedule of Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets | The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2022 and 2021: December 31, 2022 2021 (In millions) Equity securities: Overseas quoted equities $ 20 $ 38 Total equity securities 20 38 Debt securities: U.K. government bonds 71 138 U.K. corporate bonds 44 62 Total debt securities 115 200 Cash 2 16 Fair value of plan assets $ 137 $ 254 |
Schedule of Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans | The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2022, 2021, and 2020: 2022 2021 2020 Pension Postretirement Pension Postretirement Pension Postretirement (In millions) Components of Net Periodic Benefit Cost Service cost $ 2 $ 1 $ 3 $ 1 $ 3 $ 1 Interest cost 3 — 3 — 4 — Expected return on assets (4) — (4) — (5) — Amortization of loss — (1) — (1) — (1) Settlement loss — — — — — — Net periodic benefit cost $ 1 $ — $ 2 $ — $ 2 $ — Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 Discount rate 1.80 % 2.57 % 1.40 % 2.06 % 2.10 % 3.00 % Salary increases 4.90 % N/A 4.50 % N/A 4.30 % N/A Expected return on assets 1.90 % N/A 1.50 % N/A 2.20 % N/A Healthcare cost trend Initial N/A 6.25 % N/A 6.00 % N/A 6.25 % Ultimate in 2028 N/A 5.00 % N/A 5.00 % N/A 5.00 % |
Schedule of Expected Future Benefit Payment | The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Postretirement (In millions) 2023 $ 5 $ 2 2024 5 2 2025 5 2 2026 5 1 2027 5 1 Years 2028-2032 28 6 |
REDEMABLE NONCONTROLLING INTE_2
REDEMABLE NONCONTROLLING INTEREST - ALTUS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Preferred Units | Activity related to the Preferred Units for the 2022 and 2021 periods is as follows: Units Outstanding Financial Position (1) (In millions, except unit data) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2020 660,694 $ 608 Cash distributions to Altus Preferred Unit limited partners — (46) Distributions payable to Altus Preferred Unit limited partners — (12) Allocation of Altus Midstream net income N/A 80 Accreted value adjustment N/A 82 Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at December 31, 2021 660,694 712 Allocation of Altus Midstream LP net income N/A 12 Accreted value adjustment (1) N/A (82) Redeemable noncontrolling interest — Altus Preferred Unit limited partners: at February 22, 2022 660,694 642 Preferred Units embedded derivative 89 Deconsolidation of Altus (731) $ — (1) Includes the reversal of previously recorded accreted value adjustments due to the deconsolidation of Altus. N/A - not applicable. |
CAPITAL STOCK AND EQUITY (Table
CAPITAL STOCK AND EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Common Stock Outstanding | |
Schedule of Description of Stock Based Compensation Plans and Related Costs | The following table summarizes the Company’s stock-settled and cash-settled compensation costs: For the Year Ended December 31, 2022 2021 2020 (In millions) Stock-settled and cash-settled compensation expensed $ 288 $ 152 $ 40 Stock-settled and cash-settled compensation capitalized 43 18 7 Total stock-settled and cash-settled compensation costs $ 331 $ 170 $ 47 |
Schedule of Stock Options Activities | The following table summarizes stock option activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Shares Weighted Average Shares Weighted Average Shares Weighted Average (In thousands, except exercise price amounts) Outstanding, beginning of year 3,012 $ 63.79 3,537 $ 72.10 4,298 $ 75.24 Exercised (99) 42.09 — — — — Forfeited (2) 49.10 — — (37) 44.98 Expired (833) 81.56 (525) 119.83 (724) 92.14 Outstanding, end of year (1) 2,078 57.71 3,012 63.79 3,537 72.10 Expected to vest — — — — 150 45.77 Exercisable, end of year (1) 2,078 57.71 3,012 63.79 3,387 73.26 (1) As of December 31, 2022, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $3.5 million. |
Schedule of Restricted Stock and Restricted Stock Units Activity | The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2022, 2021, and 2020: 2022 2021 2020 Units Weighted Units Weighted Units Weighted (In thousands, except per share amounts) Non-vested, beginning of year 2,073 $ 19.98 1,552 $ 28.43 2,448 $ 46.65 Granted 847 29.90 1,506 16.46 1,352 24.60 Vested (3) (978) 22.39 (857) 29.13 (1,933) 48.65 Forfeited (57) 23.49 (128) 19.78 (315) 30.09 Non-vested, end of year (1)(2) 1,885 23.08 2,073 19.98 1,552 28.43 (1) As of December 31, 2022, there was $14 million of total unrecognized compensation cost related to 1,885,491 unvested stock-settled restricted stock units. (2) As of December 31, 2022, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years. (3) The grant date fair values of the stock-settled awards vested during 2022, 2021, and 2020 were approximately $22 million, $25 million, and $94 million, respectively. The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2022, 2021, and 2020: For the Year Ended December 31, 2022 2021 2020 (In thousands) Non-vested, beginning of year 6,402 4,423 5,384 Adjustment for ALTM reverse stock split (1) — — (1,246) Adjustment from ALTM transaction (2) 143 — — Granted (3) 2,568 4,441 3,462 Vested (2,970) (2,049) (1,618) Forfeited (434) (413) (1,559) Non-vested, end of year (4) 5,709 6,402 4,423 (1) Prior to the deconsolidation of Altus on February 22, 2022, on June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards were based on the per-share market price of ALTM common stock. (2) Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price. (3) Restricted stock phantom units granted during 2022, 2021, and 2020 included 2,512,602, 4,375,546, and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 55,546, 65,327, and 83,239 awards, respectively, based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above. (4) The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2022 was approximately $103 million. The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2022: Units (In thousands) Non-vested, beginning of year 4,531 Granted 1,676 Vested (656) Forfeited (106) Expired (610) Non-vested, end of year (1) 4,835 (1) As of December 31, 2022, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $53 million. |
ACCUMULATED OTHER COMPREHENSI_2
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Components of Accumulated Other Comprehensive Income (Loss) | Components of accumulated other comprehensive income (loss) include the following: As of December 31, 2022 2021 2020 (In millions) Share of equity method interests other comprehensive loss $ — $ — $ (1) Pension and postretirement benefit plan ( Note 13 ) 14 22 15 Accumulated other comprehensive income $ 14 $ 22 $ 14 |
BUSINESS SEGMENT INFORMATION (T
BUSINESS SEGMENT INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Schedule of Financial Segment Information | Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2022 Oil revenues $ 3,145 $ 1,232 $ 2,323 $ — $ — $ 6,700 Natural gas revenues 370 281 894 — — 1,545 Natural gas liquids revenues 6 45 735 — (3) 783 Oil, natural gas, and natural gas liquids production revenues 3,521 1,558 3,952 — (3) 9,028 Purchased oil and gas sales — — 1,850 5 — 1,855 Midstream service affiliate revenues — — — 16 (16) — 3,521 1,558 5,802 21 (19) 10,883 Operating Expenses: Lease operating expenses 526 404 506 — (1) 1,435 Gathering, processing, and transmission 22 43 304 5 (18) 356 Purchased oil and gas costs — — 1,776 — — 1,776 Taxes other than income — — 253 3 — 256 Exploration 84 35 24 — 3 146 Depreciation, depletion, and amortization 400 238 537 2 — 1,177 Asset retirement obligation accretion — 82 34 1 — 117 1,032 802 3,434 11 (16) 5,263 Operating Income (Loss) $ 2,489 $ 756 $ 2,368 $ 10 $ (3) 5,620 Other Income (Expense): Gain on divestitures, net 1,180 Losses on previously sold Gulf of Mexico properties (157) Derivative instrument losses, net (107) Other 139 General and administrative (462) Transaction, reorganization, and separation (26) Financing costs, net (313) Income Before Income Taxes $ 5,874 Total Assets (3) $ 3,148 $ 1,911 $ 9,196 $ — $ — $ 14,255 Net Property and Equipment $ 1,976 $ 1,386 $ 4,595 $ — $ — $ 7,957 Additions to Net Property and Equipment $ 695 $ 210 $ 752 $ — $ — $ 1,657 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2021 Oil revenues $ 1,806 $ 929 $ 1,850 $ — $ — $ 4,585 Natural gas revenues 270 183 754 — — 1,207 Natural gas liquids revenues 9 24 676 — (3) 706 Oil, natural gas, and natural gas liquids production revenues 2,085 1,136 3,280 — (3) 6,498 Purchased oil and gas sales — — 1,476 11 — 1,487 Midstream service affiliate revenues — — — 127 (127) — 2,085 1,136 4,756 138 (130) 7,985 Operating Expenses: Lease operating expenses 469 383 391 — (2) 1,241 Gathering, processing, and transmission 12 39 309 32 (128) 264 Purchased oil and gas costs — — 1,575 5 — 1,580 Taxes other than income — — 190 14 — 204 Exploration 63 34 28 — 2 127 Depreciation, depletion, and amortization 524 270 554 12 — 1,360 Asset retirement obligation accretion — 79 30 4 — 113 Impairments 26 22 — 160 — 208 1,094 827 3,077 227 (128) 5,097 Operating Income (Loss) $ 991 $ 309 $ 1,679 $ (89) $ (2) 2,888 Other Income (Expense): Gain on divestitures, net 67 Losses on previously sold Gulf of Mexico properties (446) Derivative instrument gains, net 94 Other 228 General and administrative (357) Transaction, reorganization, and separation (22) Financing costs, net (472) Income Before Income Taxes $ 1,980 Total Assets (3) $ 2,796 $ 2,199 $ 7,700 $ 1,698 $ — $ 14,393 Net Property and Equipment $ 1,720 $ 1,646 $ 4,507 $ 187 $ — $ 8,060 Additions to Net Property and Equipment $ 319 $ 159 $ 523 $ 3 $ — $ 1,004 Egypt (1) North Sea U.S. Altus Midstream Intersegment Eliminations & Other Total (2) Upstream (In millions) 2020 Oil revenues $ 1,102 $ 795 $ 1,209 $ — $ — $ 3,106 Natural gas revenues 280 67 251 — — 598 Natural gas liquids revenues 8 21 304 — — 333 Oil, natural gas, and natural gas liquids production revenues 1,390 883 1,764 — — 4,037 Purchased oil and gas sales — — 394 4 — 398 Midstream service affiliate revenues — — — 145 (145) — 1,390 883 2,158 149 (145) 4,435 Operating Expenses: Lease operating expenses 424 305 400 — (2) 1,127 Gathering, processing, and transmission 38 50 291 38 (143) 274 Purchased oil and gas costs — — 354 3 — 357 Taxes other than income — — 108 15 — 123 Exploration 63 28 168 — 15 274 Depreciation, depletion, and amortization 601 380 779 12 — 1,772 Asset retirement obligation accretion — 73 32 4 — 109 Impairments 529 7 3,963 2 — 4,501 1,655 843 6,095 74 (130) 8,537 Operating Income (Loss) $ (265) $ 40 $ (3,937) $ 75 $ (15) (4,102) Other Income (Expense): Gain on divestitures, net 32 Derivative instrument losses, net (223) Other 64 General and administrative (290) Transaction, reorganization, and separation (54) Financing costs, net (267) Loss Before Income Taxes $ (4,840) Total Assets (3) $ 3,003 $ 2,220 $ 5,540 $ 1,786 $ 197 $ 12,746 Net Property and Equipment $ 1,955 $ 1,773 $ 4,760 $ 196 $ 135 $ 8,819 Additions to Net Property and Equipment $ 454 $ 215 $ 345 $ 12 $ 136 $ 1,162 (1) Includes revenue from non-customers for the years ended December 31, 2022, 2021, and 2020 of: For the Year Ended December 31, 2022 2021 2020 (In millions) Oil $ 989 $ 420 $ 95 Natural gas 117 47 14 Natural gas liquids 2 2 — (2) Includes noncontrolling interests in Egypt and Altus Midstream. (3) Intercompany balances are excluded from total assets. |
SUPPLEMENTAL OIL AND GAS DISC_2
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Schedule of Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities | The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities. United Egypt (1) North Sea Other Total (1) (In millions, except per boe) 2022 Oil and gas production revenues $ 3,952 $ 3,521 $ 1,558 $ — $ 9,031 Operating cost: Depreciation, depletion, and amortization (2) 508 390 232 — 1,130 Asset retirement obligation accretion 34 — 82 — 116 Lease operating expenses 506 526 404 — 1,436 Gathering, processing, and transmission 304 22 43 — 369 Exploration expenses 24 84 35 3 146 Production taxes (3) 252 — — — 252 Income tax 488 1,100 495 — 2,083 2,116 2,122 1,291 3 5,532 Results of operations $ 1,836 $ 1,399 $ 267 $ (3) $ 3,499 2021 Oil and gas production revenues $ 3,280 $ 2,085 $ 1,136 $ — $ 6,501 Operating cost: Depreciation, depletion, and amortization (2) 511 477 267 — 1,255 Asset retirement obligation accretion 30 — 79 — 109 Lease operating expenses 391 469 383 — 1,243 Gathering, processing, and transmission 309 12 39 — 360 Exploration expenses 28 63 34 2 127 Production taxes (3) 188 — — — 188 Income tax 383 479 134 — 996 1,840 1,500 936 2 4,278 Results of operations $ 1,440 $ 585 $ 200 $ (2) $ 2,223 2020 Oil and gas production revenues $ 1,764 $ 1,390 $ 883 $ — $ 4,037 Operating cost: Depreciation, depletion, and amortization (2) 726 540 377 — 1,643 Asset retirement obligation accretion 32 — 73 — 105 Lease operating expenses 400 424 305 — 1,129 Gathering, processing, and transmission 291 38 50 — 379 Exploration expenses 168 63 28 15 274 Impairments related to oil and gas properties 3,938 374 7 — 4,319 Production taxes (3) 106 — — — 106 Income tax (818) (22) 17 — (823) 4,843 1,417 857 15 7,132 Results of operations $ (3,079) $ (27) $ 26 $ (15) $ (3,095) (1) Includes noncontrolling interests in Egypt. (2) Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 18—Business Segment Information . (3) Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 18—Business Segment Information . |
Schedule of Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities | Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities United Egypt (2) North Sea Other Total (2) (In millions) 2022 Acquisitions: Proved $ 19 $ 3 $ — $ — $ 22 Unproved 28 — — — 28 Exploration 4 169 61 3 237 Development 775 568 (57) — 1,286 Costs incurred (1) $ 826 $ 740 $ 4 $ 3 $ 1,573 (1) Includes capitalized interest, asset retirement costs: Capitalized interest $ — $ — $ 1 $ — $ 1 Asset retirement costs 76 — (215) — (139) 2021 Acquisitions: Proved $ — $ (157) $ — $ — $ (157) Unproved 9 20 — — 29 Exploration 6 86 39 30 161 Development 545 404 135 1 1,085 Costs incurred (1) $ 560 $ 353 $ 174 $ 31 $ 1,118 (1) Includes capitalized interest and asset retirement costs, and Egypt modernization impacts as follows: Capitalized interest $ — $ — $ — $ — $ — Asset retirement costs 130 — 19 — 149 Egypt PSC modernization impacts - Proved and Unproved — (145) — — (145) 2020 Acquisitions: Proved $ — $ 7 $ — $ — $ 7 Unproved 4 — — — 4 Exploration 8 102 68 150 328 Development 332 378 162 — 872 Costs incurred (1) $ 344 $ 487 $ 230 $ 150 $ 1,211 (1) Includes capitalized interest and asset retirement costs as follows: Capitalized interest $ — $ — $ — $ 3 $ 3 Asset retirement costs 9 — 29 — 38 (2) Includes a noncontrolling interest in Egypt. The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities: United Egypt (1) North Other Total (1) (In millions) 2022 Proved properties $ 18,990 $ 13,014 $ 8,945 $ — $ 40,949 Unproved properties 208 77 11 — 296 19,198 13,091 8,956 — 41,245 Accumulated DD&A (14,846) (11,157) (7,573) — (33,576) $ 4,352 $ 1,934 $ 1,383 $ — $ 7,669 2021 Proved properties $ 18,732 $ 12,373 $ 8,954 $ — $ 40,059 Unproved properties 319 63 33 — 415 19,051 12,436 8,987 — 40,474 Accumulated DD&A (14,814) (10,767) (7,345) — (32,926) $ 4,237 $ 1,669 $ 1,642 $ — $ 7,548 |
Schedule of Proved Reserve Data | There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Crude Oil and Condensate United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2019 278,145 103,573 101,712 483,430 December 31, 2020 206,936 95,981 86,566 389,483 December 31, 2021 180,968 106,646 77,073 364,687 December 31, 2022 168,817 108,050 82,580 359,447 Proved undeveloped reserves: December 31, 2019 46,716 10,831 10,049 67,596 December 31, 2020 25,516 11,228 7,273 44,017 December 31, 2021 18,168 11,003 5,757 34,928 December 31, 2022 16,221 8,557 2,873 27,651 Total proved reserves: Balance December 31, 2019 324,861 114,404 111,761 551,026 Extensions, discoveries and other additions 17,858 17,855 5,275 40,988 Revisions of previous estimates (69,247) 2,541 (4,756) (71,462) Production (32,299) (27,591) (18,441) (78,331) Sales of minerals in-place (8,721) — — (8,721) Balance December 31, 2020 232,452 107,209 93,839 433,500 Extensions, discoveries and other additions 17,869 13,390 2,288 33,547 Purchases of minerals in-place 126 — — 126 Revisions of previous estimates (4,479) 22,727 (60) 18,188 Production (27,450) (25,677) (13,237) (66,364) Sales of minerals in-place (19,382) — — (19,382) Balance December 31, 2021 199,136 117,649 82,830 399,615 Extensions, discoveries and other additions 9,776 7,580 2,616 19,972 Purchases of minerals in-place 522 — — 522 Revisions of previous estimates 7,170 22,433 11,898 41,501 Production (24,141) (31,055) (11,891) (67,087) Sales of minerals in-place (7,425) — — (7,425) Balance December 31, 2022 185,038 116,607 85,453 387,098 (1) Includes proved reserves of 62 MMbbls, 39 MMbbls, 36 MMbbls, and 38 MMbbls as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Natural Gas Liquids United Egypt (1) North Total (1) (Thousands of barrels) Proved developed reserves: December 31, 2019 158,794 667 2,317 161,778 December 31, 2020 150,599 716 2,053 153,368 December 31, 2021 164,172 446 2,059 166,677 December 31, 2022 152,999 — 2,230 155,229 Proved undeveloped reserves: December 31, 2019 23,569 90 660 24,319 December 31, 2020 15,141 126 320 15,587 December 31, 2021 16,380 30 275 16,685 December 31, 2022 15,398 — 76 15,474 Total proved reserves: Balance December 31, 2019 182,363 757 2,977 186,097 Extensions, discoveries and other additions 11,435 97 312 11,844 Revisions of previous estimates (469) 264 (207) (412) Production (27,133) (276) (709) (28,118) Sales of minerals in-place (456) — — (456) Balance December 31, 2020 165,740 842 2,373 168,955 Extensions, discoveries and other additions 21,055 7 81 21,143 Purchases of minerals in-place 191 — — 191 Revisions of previous estimates 22,724 (180) 318 22,862 Production (24,175) (193) (438) (24,806) Sales of minerals in-place (4,983) — — (4,983) Balance December 31, 2021 180,552 476 2,334 183,362 Extensions, discoveries and other additions 5,456 — 45 5,501 Purchases of minerals in-place 233 — — 233 Revisions of previous estimates 10,355 (407) 333 10,281 Production (21,859) (69) (406) (22,334) Sales of minerals in-place (6,340) — — (6,340) Balance December 31, 2022 168,397 — 2,306 170,703 (1) Includes proved reserves of 159 Mbbls, 281 Mbbls, and 252 Mbbls as of December 31, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Natural Gas United Egypt (1) North Total (1) (Millions of cubic feet) Proved developed reserves: December 31, 2019 945,938 433,382 106,329 1,485,649 December 31, 2020 1,052,756 409,035 68,159 1,529,950 December 31, 2021 1,237,461 464,826 76,155 1,778,442 December 31, 2022 1,128,066 399,502 66,292 1,593,860 Proved undeveloped reserves: December 31, 2019 115,040 24,704 16,604 156,348 December 31, 2020 76,504 12,572 8,341 97,417 December 31, 2021 184,441 9,899 7,124 201,464 December 31, 2022 188,976 1,068 2,304 192,348 Total proved reserves: Balance December 31, 2019 1,060,978 458,086 122,933 1,641,997 Extensions, discoveries and other additions 60,965 83,718 8,140 152,823 Revisions of previous estimates 215,166 (19,849) (33,541) 161,776 Production (205,594) (100,348) (21,032) (326,974) Sales of minerals in-place (2,255) — — (2,255) Balance December 31, 2020 1,129,260 421,607 76,500 1,627,367 Extensions, discoveries and other additions 227,684 50,209 3,684 281,577 Purchases of minerals in-place 839 — — 839 Revisions of previous estimates 279,610 99,143 17,171 395,924 Production (192,523) (96,234) (14,076) (302,833) Sales of minerals in-place (22,968) — — (22,968) Balance December 31, 2021 1,421,902 474,725 83,279 1,979,906 Extensions, discoveries and other additions 38,157 10,191 1,643 49,991 Purchases of minerals in-place 1,592 — — 1,592 Revisions of previous estimates 96,381 45,725 (3,431) 138,675 Production (167,580) (130,071) (12,895) (310,546) Sales of minerals in-place (73,410) — — (73,410) Balance December 31, 2022 1,317,042 400,570 68,596 1,786,208 (1) Includes proved reserves of 224 Bcf, 158 Bcf, 141 Bcf, and 153 Bcf as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. Total Equivalent Reserves United Egypt (1) North Total (1) (Thousands barrels of oil equivalent) Proved developed reserves: December 31, 2019 594,595 176,470 121,751 892,816 December 31, 2020 532,994 164,870 99,979 797,843 December 31, 2021 551,384 184,563 91,825 827,772 December 31, 2022 509,827 174,633 95,859 780,319 Proved undeveloped reserves: December 31, 2019 89,458 15,038 13,476 117,972 December 31, 2020 53,408 13,449 8,983 75,840 December 31, 2021 65,288 12,683 7,219 85,190 December 31, 2022 63,115 8,735 3,333 75,183 Total proved reserves: Balance December 31, 2019 684,053 191,508 135,227 1,010,788 Extensions, discoveries and other additions 39,454 31,905 6,944 78,303 Revisions of previous estimates (33,854) (502) (10,554) (44,910) Production (93,698) (44,592) (22,655) (160,945) Sales of minerals in-place (9,553) — — (9,553) Balance December 31, 2020 586,402 178,319 108,962 873,683 Extensions, discoveries and other additions 76,871 21,765 2,983 101,619 Purchases of minerals in-place 457 — — 457 Revisions of previous estimates 64,847 39,071 3,120 107,038 Production (83,712) (41,909) (16,021) (141,642) Sales of minerals in-place (28,193) — — (28,193) Balance December 31, 2021 616,672 197,246 99,044 912,962 Extensions, discoveries and other additions 21,592 9,278 2,935 33,805 Purchases of minerals in-place 1,020 — — 1,020 Revisions of previous estimates 33,588 29,647 11,659 74,894 Production (73,930) (52,803) (14,446) (141,179) Sales of minerals in-place (26,000) — — (26,000) Balance December 31, 2022 572,942 183,368 99,192 855,502 (1) Includes total proved reserves of 99 MMboe, 66 MMboe, 59 MMboe, and 64 MMboe as of December 31, 2022, 2021, 2020, and 2019, respectively, attributable to noncontrolling interests in Egypt. |
Schedule of Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense | The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2022, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. United Egypt (1) North Total (1) (In millions) 2022 Cash inflows $ 29,490 $ 12,819 $ 10,147 $ 52,456 Production costs (10,221) (2,086) (3,241) (15,548) Development costs (1,598) (1,471) (2,297) (5,366) Income tax expense (1,389) (2,729) (2,631) (6,749) Net cash flows 16,282 6,533 1,978 24,793 10 percent discount rate (6,422) (1,400) (204) (8,026) Discounted future net cash flows (2) $ 9,860 $ 5,133 $ 1,774 $ 16,767 2021 Cash inflows $ 22,852 $ 9,337 $ 6,832 $ 39,021 Production costs (8,323) (1,712) (2,343) (12,378) Development costs (1,632) (1,402) (2,533) (5,567) Income tax expense (134) (1,887) (768) (2,789) Net cash flows 12,763 4,336 1,188 18,287 10 percent discount rate (5,294) (983) 350 (5,927) Discounted future net cash flows (2) $ 7,469 $ 3,353 $ 1,538 $ 12,360 2020 Cash inflows $ 12,537 $ 5,560 $ 4,122 $ 22,219 Production costs (6,244) (1,704) (2,388) (10,336) Development costs (1,555) (633) (2,448) (4,636) Income tax expense — (1,096) 316 (780) Net cash flows 4,738 2,127 (398) 6,467 10 percent discount rate (1,829) (437) 1,111 (1,155) Discounted future net cash flows (2) $ 2,909 $ 1,690 $ 713 $ 5,312 (1) Includes discounted future net cash flows of approximately $2.5 billion , $1.6 billion, and $563 million as of December 31, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $16.1 billion , $14.9 billion, and $7.1 billion as of December 31, 2022, 2021, and 2020, respectively. |
Schedule of Principal Sources of Change In Discounted Future Net Cash Flows | The following table sets forth the principal sources of change in the discounted future net cash flows: For the Year Ended December 31, 2022 2021 2020 (In millions) Sales, net of production costs $ (6,970) $ (4,707) $ (2,422) Net change in prices and production costs 8,627 9,376 (5,753) Discoveries and improved recovery, net of related costs 1,132 1,749 751 Change in future development costs (347) (839) 20 Previously estimated development costs incurred during the period 669 545 576 Revision of quantities 2,621 1,983 (418) Purchases of minerals in-place 17 1 — Accretion of discount 1,489 626 1,236 Change in income taxes (2,371) (1,583) 1,533 Sales of minerals in-place (363) (116) (104) Change in production rates and other (97) 13 11 $ 4,407 $ 7,048 $ (4,570) |
NATURE OF OPERATIONS (Details)
NATURE OF OPERATIONS (Details) | 12 Months Ended |
Dec. 31, 2022 Area | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of geographical areas | 3 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Dec. 27, 2021 | Dec. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Feb. 22, 2022 | ||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Asset impairments | $ 0 | $ 208,000,000 | $ 4,501,000,000 | ||||||
Equity method investment impairment | $ 160,000,000 | 0 | 160,000,000 | 0 | |||||
Inventory and other | 0 | 48,000,000 | 27,000,000 | ||||||
Impairments | 0 | 208,000,000 | 4,501,000,000 | ||||||
Goodwill impairment | 0 | 0 | 87,000,000 | ||||||
Goodwill | 0 | $ 0 | 0 | 0 | 0 | ||||
Impairment for early termination of drilling rig leases | 13,000,000 | ||||||||
Inventory write-downs | 5,000,000 | ||||||||
Other asset impairments | 9,000,000 | ||||||||
PSC, percentage of gross acreage consolidated | 98% | ||||||||
PSC, percentage of gross production consolidated | 90% | ||||||||
PSC, development lease term | 20 years | ||||||||
PSC, exploration lease term | 5 years | ||||||||
PSC, cost recovery limit | 40% | ||||||||
PSC, fixed profit-sharing rate | 30% | ||||||||
Receivables from contracts with customers, net of allowance for doubtful accounts | 1,300,000,000 | 1,300,000,000 | 1,300,000,000 | ||||||
Cash and cash equivalent | [1] | 279,000,000 | 185,000,000 | 279,000,000 | |||||
Restricted cash | 0 | 0 | 0 | ||||||
Oil and gas property impaired, fair value | 1,900,000,000 | 1,900,000,000 | |||||||
Gathering, processing, and transmission facilities ($209 related to Altus VIE) | [1] | 673,000,000 | 449,000,000 | 673,000,000 | |||||
GPT facilities, accumulated depreciation | 386,000,000 | 367,000,000 | 386,000,000 | ||||||
Deconsolidated assets | $ 183,000,000 | ||||||||
Other property and equipment | 225,000,000 | 206,000,000 | 225,000,000 | ||||||
Restructuring cumulative cost incurred to date | 79,000,000 | 79,000,000 | |||||||
Transaction, reorganization, and separation | 26,000,000 | 22,000,000 | 54,000,000 | ||||||
Egypt | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Goodwill impairment | $ 87,000,000 | ||||||||
Reorganization Activities | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Transaction, reorganization, and separation | 15,000,000 | 17,000,000 | |||||||
Consulting Fees | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Transaction, reorganization, and separation | 9,000,000 | 11,000,000 | 2,000,000 | ||||||
Separation costs | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Transaction, reorganization, and separation | 6,000,000 | 6,000,000 | 51,000,000 | ||||||
Business Combination Costs | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Transaction, reorganization, and separation | 11,000,000 | 5,000,000 | |||||||
Office closure | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Transaction, reorganization, and separation | 1,000,000 | ||||||||
Oil and gas proved property | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Impairments | 0 | 0 | 4,319,000,000 | ||||||
Tangible asset impairment charges | $ 20,000,000 | 0 | 0 | $ 4,319,000,000 | |||||
Oil and gas proved property | Significant Unobservable Inputs (Level 3) | Measurement Input, Discount Rate | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Oil and gas properties, measurement inputs | 10% | 10% | |||||||
Gathering, processing, and transmission facilities | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Oil and gas property impaired, fair value | 46,000,000 | ||||||||
Tangible asset impairment charges | 68,000,000 | $ 0 | 0 | $ 68,000,000 | |||||
Other Property and Equipment | Minimum | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Useful lives of gas gathering, transmission and processing facilities | 3 years | ||||||||
Other Property and Equipment | Maximum | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Useful lives of gas gathering, transmission and processing facilities | 20 years | ||||||||
Altus | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Equity method investment impairment | 160,000,000 | ||||||||
Cash and cash equivalent | $ 132,000,000 | 132,000,000 | |||||||
United States | Oil and gas proved property | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Impairments | 3,900,000,000 | $ 0 | 0 | 3,938,000,000 | |||||
Egypt | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Inventory and other | 26,000,000 | ||||||||
Egypt | Oil and gas proved property | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Impairments | 354,000,000 | 0 | 0 | 374,000,000 | |||||
North Sea | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Inventory and other | 22,000,000 | ||||||||
North Sea | Oil and gas proved property | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Impairments | $ 7,000,000 | $ 0 | $ 0 | $ 7,000,000 | |||||
Apache Egypt | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Noncontrolling interest, ownership percentage by parent | 66.67% | ||||||||
Apache Egypt | Sinopec | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Ownership percentage | 33.33% | ||||||||
Altus | Third-party investors | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Ownership percentage | 21% | ||||||||
Kinetik | |||||||||
Schedule Of Significant Accounting Policies [Line Items] | |||||||||
Ownership percentage | 10% | ||||||||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Impairments Recorded in Connection with Fair Value Assessments (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Dec. 31, 2021 | Mar. 31, 2020 | Dec. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Equity method interests | $ 160 | $ 0 | $ 160 | $ 0 | ||
Goodwill | 0 | 0 | 87 | |||
Inventory and other | 0 | 48 | 27 | |||
Impairments | 0 | 208 | 4,501 | |||
Oil and gas proved property | ||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Tangible asset impairment charges | $ 20 | 0 | 0 | 4,319 | ||
Gathering, processing, and transmission facilities | ||||||
Schedule Of Significant Accounting Policies [Line Items] | ||||||
Tangible asset impairment charges | $ 68 | $ 0 | $ 0 | $ 68 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Credit Loss Roll-forward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Allowance for credit loss at beginning of year | $ 109 | $ 95 | $ 88 |
Additional provisions for the year | 9 | 19 | 7 |
Uncollectible accounts written off, net of recoveries | (1) | (5) | 0 |
Allowance for credit loss at end of year | $ 117 | $ 109 | $ 95 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | $ 0 | $ 208 | $ 4,501 | |
Oil and gas proved property | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | 0 | 0 | 4,319 | |
Oil and Gas Properties, Unproved | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | 24 | 31 | 101 | |
U.S. | Oil and gas proved property | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | $ 3,900 | 0 | 0 | 3,938 |
U.S. | Oil and Gas Properties, Unproved | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | 20 | 22 | 92 | |
Egypt | Oil and gas proved property | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | 354 | 0 | 0 | 374 |
Egypt | Oil and Gas Properties, Unproved | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | 4 | 8 | 8 | |
North Sea | Oil and gas proved property | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | $ 7 | 0 | 0 | 7 |
North Sea | Oil and Gas Properties, Unproved | ||||
Schedule Of Significant Accounting Policies [Line Items] | ||||
Impairments | $ 0 | $ 1 | $ 1 |
TRANSACTIONS WITH PARENT AFFI_2
TRANSACTIONS WITH PARENT AFFILIATE (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | 18 Months Ended | ||||||||
Mar. 01, 2021 USD ($) subsidiary | Apr. 30, 2022 USD ($) | Aug. 31, 2021 USD ($) | Sep. 30, 2022 USD ($) | Jun. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Aug. 31, 2022 USD ($) | ||||
Related Party Transaction [Line Items] | ||||||||||||
Interest income with parent affiliate | $ 63 | $ 51 | ||||||||||
Note receivable, increase, accrued interest | $ 93 | |||||||||||
Distributed in cash | 216 | |||||||||||
Reimbursable costs charged to Parent | 18 | 17 | ||||||||||
Note payable to APA Corporation (Note 2) | [1] | 0 | 195 | |||||||||
Noncurrent receivable from APA Corporation | 869 | [1] | 0 | |||||||||
Current receivable from APA Corporation | 0 | 77 | [1] | |||||||||
Payments of capital distribution | 894 | 839 | ||||||||||
Noncontrolling Interest, APA Corporation | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Net income (loss) attributable to noncontrolling interest | $ 278 | $ 0 | $ 0 | |||||||||
Net Income And Distributable Cash Flow For Egyptian Operations | Sinopec | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Ownership percentage | 30% | |||||||||||
Affiliated Entity | Promissory Note | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Debt face amount | $ 250 | |||||||||||
Debt term | 1 year | |||||||||||
Affiliated Entity | Promissory Note Due April 28, 2023 | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Debt face amount | $ 680 | |||||||||||
Debt term | 1 year | |||||||||||
Repayments of debt | $ 349 | $ 331 | ||||||||||
Holding Company Reorganization | Affiliated Entity | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Number of subsidiaries | subsidiary | 3 | |||||||||||
Note receivable, term | 7 years | |||||||||||
Note receivable, interest rate | 4.50% | |||||||||||
Note receivable, accrued interest converted to principal, term | 5 years 6 months | |||||||||||
Holding Company Reorganization | Affiliated Entity | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Three Apache Subsidiaries | ||||||||||||
Related Party Transaction [Line Items] | ||||||||||||
Net assets transferred | $ 483 | |||||||||||
Cash and cash equivalents transferred | 292 | |||||||||||
Oil and gas properties, and working capital items transferred | $ 163 | |||||||||||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - 2022 Activity (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Mar. 11, 2022 | Feb. 22, 2022 | Mar. 31, 2022 | Mar. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Feb. 21, 2022 | |
Business Acquisition [Line Items] | ||||||||
Proceeds from asset divestitures | $ 778 | $ 256 | $ 166 | |||||
Gain on deconsolidation of ALTM | $ 609 | |||||||
Number of shares issued in transaction (in shares) | 4 | |||||||
Proceeds from sale of stock | $ 224 | |||||||
Gain (loss) on disposition of stock | $ (25) | |||||||
Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of shares issued in transaction (in shares) | 4 | 4 | ||||||
Gain (loss) on disposition of stock | $ 25 | |||||||
Expected future minimum investment, period | 24 months | |||||||
Expected future minimum investment, amount | $ 100 | $ 100 | ||||||
Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage | 10% | |||||||
Apache Midstream LLC | ALTM | ||||||||
Business Acquisition [Line Items] | ||||||||
Noncontrolling interest, ownership percentage by parent | 79% | |||||||
BCP Business Combination | Altus Midstream | ALTM | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership percentage | 20% | |||||||
BCP Business Combination | BCP Business Combination Contributor | Kinetik | ||||||||
Business Acquisition [Line Items] | ||||||||
Noncontrolling interest, ownership percentage by parent | 75% | |||||||
BCP Business Combination | Common Class C | Altus Midstream | ||||||||
Business Acquisition [Line Items] | ||||||||
Business acquisition, equity interest issued or issuable (in shares) | 50 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-Core Assets And Leasehold | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from asset divestitures | $ 52 | |||||||
Gain (loss) on sale of oil and gas properties | 36 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-Core Mineral Rights | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from asset divestitures | 726 | |||||||
Gain (loss) on sale of oil and gas properties | $ 560 | |||||||
Permian Basin | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from asset divestitures | $ 37 |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Components of Deconsolidation (Details) - USD ($) $ in Millions | Feb. 22, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Business Acquisition [Line Items] | ||||
Fair value of Kinetik Class A Common Stock held by Company | [1] | $ 624 | $ 1,365 | |
ASSETS: | ||||
Cash and cash equivalents | $ 143 | |||
Other current assets | 29 | |||
Property and equipment, net | 184 | |||
Equity method interests | 1,367 | |||
Other noncurrent assets | 12 | |||
Total assets deconsolidated | 1,735 | |||
LIABILITIES: | ||||
Current liabilities | 3 | |||
Long-term debt | 657 | |||
Other noncurrent liabilities | 168 | |||
Total liabilities deconsolidated | 828 | |||
NONCONTROLLING INTERESTS: | ||||
Redeemable noncontrolling interest preferred unit limited partners | 642 | |||
Noncontrolling interest-Altus | 72 | |||
Total noncontrolling interests deconsolidated | 714 | |||
Net effect of deconsolidating balance sheet | (193) | |||
Gain on deconsolidation of ALTM | 609 | |||
Kinetik | ||||
Business Acquisition [Line Items] | ||||
Fair value of Kinetik Class A Common Stock held by Company | $ 802 | $ 624 | $ 0 | |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
ACQUISITIONS AND DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES - 2021 Activity (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2021 | Dec. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Business Acquisition [Line Items] | |||||
Proceeds from asset divestitures | $ 778 | $ 256 | $ 166 | ||
Leasehold and property acquisitions amount | $ 37 | 9 | 4 | ||
Permian Region | |||||
Business Acquisition [Line Items] | |||||
Leasehold and property acquisitions amount | $ 9 | 4 | |||
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations | |||||
Business Acquisition [Line Items] | |||||
Net Property and Equipment | $ 157 | ||||
Proceeds from asset divestitures | 176 | 87 | |||
Asset retirement obligation assumed | 44 | ||||
Gain (loss) on sale of oil and gas properties | $ 63 | $ 13 | |||
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Other Non-Core Assets And Leasehold | |||||
Business Acquisition [Line Items] | |||||
Proceeds from asset divestitures | $ 80 | ||||
Gain (loss) on sale of oil and gas properties | $ 4 |
ACQUISITIONS AND DIVESTITURES_4
ACQUISITIONS AND DIVESTITURES - 2020 Activity (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Business Acquisition [Line Items] | ||||
Leasehold and property acquisitions amount | $ 37 | $ 9 | $ 4 | |
Proceeds from sale of oil and gas properties | $ 778 | 256 | 166 | |
Gain (loss) on investment in joint venture | 19 | |||
Permian Region | ||||
Business Acquisition [Line Items] | ||||
Leasehold and property acquisitions amount | $ 9 | 4 | ||
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||
Business Acquisition [Line Items] | ||||
Proceeds from sale of oil and gas properties | $ 176 | 87 | ||
Gain (loss) on sale of oil and gas properties | $ 63 | $ 13 |
CAPITALIZED EXPLORATORY WELL _3
CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Capitalized well costs at beginning of year | $ 46 | $ 197 | $ 141 |
Additions pending determination of proved reserves | 138 | 62 | 226 |
Divestitures and other | 0 | (163) | (38) |
Reclassifications to proved properties | (110) | (40) | (56) |
Charged to exploration expense | (24) | (10) | (76) |
Capitalized well costs at end of year | $ 50 | $ 46 | $ 197 |
CAPITALIZED EXPLORATORY WELL _4
CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions | Dec. 31, 2022 USD ($) Project | Dec. 31, 2021 USD ($) Project | Dec. 31, 2020 USD ($) Project | Dec. 31, 2019 USD ($) |
Extractive Industries [Abstract] | ||||
Exploratory well costs capitalized for a period of one year or less | $ 34 | $ 13 | $ 184 | |
Exploratory well costs capitalized for a period greater than one year | 16 | 33 | 13 | |
Capitalized exploratory well costs | $ 50 | $ 46 | $ 197 | $ 141 |
Number of projects with exploratory well costs capitalized for a period greater than one year | Project | 10,000,000 | 9,000,000 | 5 |
CAPITALIZED EXPLORATORY WELL _5
CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | $ 16 | $ 33 | $ 13 |
North Sea | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | $ 2 | $ 24 |
CAPITALIZED EXPLORATORY WELL _6
CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | $ 16 | $ 33 | $ 13 |
2021 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 7 | ||
2020 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 0 | ||
2019 and Prior | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 9 | ||
Egypt | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 14 | ||
Egypt | 2021 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 5 | ||
Egypt | 2020 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 0 | ||
Egypt | 2019 and Prior | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 9 | ||
North Sea | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 2 | $ 24 | |
North Sea | 2021 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 2 | ||
North Sea | 2020 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | 0 | ||
North Sea | 2019 and Prior | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs capitalized for a period greater than one year | $ 0 |
DERIVATIVE INSTRUMENTS AND HE_3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2022 | Nov. 30, 2022 | Dec. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Derivative liability | $ 0 | $ 0 | $ 37 | $ 113 |
Derivative, mark-to-market loss | $ 37 | |||
Derivative Loss, Statement Of Income Or Comprehensive Income, Extensible Enumeration Not Disclosed Flag | statement of consolidated operation |
DERIVATIVE INSTRUMENTS AND HE_4
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Nov. 30, 2022 | Dec. 31, 2021 |
Assets: | |||
Derivative asset | $ 0 | $ 0 | |
Liabilities: | |||
Derivative liability | 0 | $ 37 | 113 |
Commodity Derivative Instruments | Recurring | |||
Assets: | |||
Derivative asset, fair value | 0 | ||
Derivative asset, netting | 0 | ||
Derivative asset | 0 | ||
Liabilities: | |||
Derivative liability, fair value | 0 | 10 | |
Derivative liability, netting | 0 | 0 | |
Derivative liability | 0 | 10 | |
Commodity Derivative Instruments | Recurring | Quoted Price in Active Markets (Level 1) | |||
Assets: | |||
Derivative asset, fair value | 0 | ||
Liabilities: | |||
Derivative liability, fair value | 0 | 0 | |
Commodity Derivative Instruments | Recurring | Significant Other Inputs (Level 2) | |||
Assets: | |||
Derivative asset, fair value | 0 | ||
Liabilities: | |||
Derivative liability, fair value | 0 | 10 | |
Commodity Derivative Instruments | Recurring | Significant Unobservable Inputs (Level 3) | |||
Assets: | |||
Derivative asset, fair value | 0 | ||
Liabilities: | |||
Derivative liability, fair value | $ 0 | 0 | |
Pipeline capacity embedded derivatives | Recurring | |||
Liabilities: | |||
Derivative liability, fair value | 46 | ||
Derivative liability, netting | 0 | ||
Derivative liability | 46 | ||
Pipeline capacity embedded derivatives | Recurring | Quoted Price in Active Markets (Level 1) | |||
Liabilities: | |||
Derivative liability, fair value | 0 | ||
Pipeline capacity embedded derivatives | Recurring | Significant Other Inputs (Level 2) | |||
Liabilities: | |||
Derivative liability, fair value | 46 | ||
Pipeline capacity embedded derivatives | Recurring | Significant Unobservable Inputs (Level 3) | |||
Liabilities: | |||
Derivative liability, fair value | 0 | ||
Preferred Units embedded derivative | Recurring | |||
Liabilities: | |||
Derivative liability, fair value | 57 | ||
Derivative liability, netting | 0 | ||
Derivative liability | 57 | ||
Preferred Units embedded derivative | Recurring | Quoted Price in Active Markets (Level 1) | |||
Liabilities: | |||
Derivative liability, fair value | 0 | ||
Preferred Units embedded derivative | Recurring | Significant Other Inputs (Level 2) | |||
Liabilities: | |||
Derivative liability, fair value | 0 | ||
Preferred Units embedded derivative | Recurring | Significant Unobservable Inputs (Level 3) | |||
Liabilities: | |||
Derivative liability, fair value | $ 57 |
DERIVATIVE INSTRUMENTS AND HE_5
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Nov. 30, 2022 | Dec. 31, 2021 |
Derivatives, Fair Value [Line Items] | |||
Derivative asset | $ 0 | $ 0 | |
Derivative liability | 0 | $ 37 | 113 |
Current Assets: Other current assets | |||
Derivatives, Fair Value [Line Items] | |||
Derivative asset | $ 0 | $ 0 | |
Derivative Asset, Statement of Financial Position [Extensible Enumeration] | Other current assets (Note 6) ($9 related to Altus VIE) | Other current assets (Note 6) ($9 related to Altus VIE) | |
Other Assets: Deferred charges and other | |||
Derivatives, Fair Value [Line Items] | |||
Derivative asset | $ 0 | $ 0 | |
Derivative Asset, Statement of Financial Position [Extensible Enumeration] | Deferred charges and other ($6 related to Altus VIE) | Deferred charges and other ($6 related to Altus VIE) | |
Current Liabilities: Other current liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liability | $ 0 | $ 4 | |
Derivative Liability, Statement of Financial Position [Extensible Enumeration] | Other current liabilities (Note 8) ($15 related to Altus VIE) | Other current liabilities (Note 8) ($15 related to Altus VIE) | |
Deferred Credits and Other Noncurrent Liabilities: Other | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liability | $ 0 | $ 109 | |
Derivative Liability, Statement of Financial Position [Extensible Enumeration] | Liabilities, Other than Long-Term Debt, Noncurrent | Liabilities, Other than Long-Term Debt, Noncurrent |
DERIVATIVE INSTRUMENTS AND HE_6
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain (loss), net | $ (23) | $ 69 | $ (87) |
Derivative instrument gains (losses), net | (107) | 94 | (223) |
Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Realized gain (loss), net | (85) | 25 | (136) |
Unrealized gain (loss), net | (22) | 69 | (87) |
Derivative instrument gains (losses), net | (107) | 94 | (223) |
Commodity Derivative Instruments | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Realized gain (loss), net | (72) | 25 | (135) |
Unrealized gain (loss), net | 9 | (20) | 11 |
Pipeline capacity embedded derivatives | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain (loss), net | 0 | 7 | (61) |
Foreign currency derivative instruments | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Realized gain (loss), net | (13) | 0 | (1) |
Unrealized gain (loss), net | 0 | 0 | (1) |
Preferred Units embedded derivative | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized gain (loss), net | $ (31) | $ 82 | $ (36) |
OTHER CURRENT ASSETS (Details)
OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||
Inventories | $ 425 | $ 438 | |
Drilling advances | 64 | 55 | |
Prepaid assets and other | 54 | 56 | |
Current decommissioning security for sold Gulf of Mexico assets | 450 | 100 | |
Total Other current assets | [1] | $ 993 | $ 649 |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
EQUITY METHOD INTERESTS - Addit
EQUITY METHOD INTERESTS - Additional Information (Details) shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Mar. 11, 2022 shares | Mar. 31, 2022 USD ($) shares | Jun. 30, 2022 | Dec. 31, 2022 USD ($) shares | Dec. 31, 2021 USD ($) entity | Dec. 31, 2020 USD ($) | Feb. 22, 2022 shares | |
Schedule of Equity Method Investments [Line Items] | |||||||
Number of shares issued in transaction (in shares) | shares | 4 | ||||||
Loss on sale of stock | $ 25 | ||||||
Proceeds from asset divestitures | $ 778 | $ 256 | $ 166 | ||||
Kinetik | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity method investment, number of shares (in share) | shares | 18.9 | 12.9 | |||||
Number of shares issued in transaction (in shares) | shares | 4 | 4 | |||||
Loss on sale of stock | $ (25) | ||||||
Dividends paid-in-kind (in shares) | shares | 1.1 | ||||||
Gain (loss) on equity fair value adjustment | $ 32 | ||||||
Interest | 13% | ||||||
Gathering, processing and transportation costs | $ 91 | ||||||
Gathering, processing and transportation costs payable | 17 | ||||||
Revenue | 8 | ||||||
Accrued Receivables from investee | $ 8 | ||||||
Kinetik | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Reverse stock split ratio | 2 | ||||||
Altus | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Number of long-haul pipeline entities | entity | 4 |
EQUITY METHOD INTERESTS - Roll
EQUITY METHOD INTERESTS - Roll Forward Activity of Kinetik Holdings (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 USD ($) | ||
Movement In Equity Method Interests [Roll Forward] | ||
Equity method interest, beginning balance | $ 1,365 | [1] |
Equity method interest, ending balance | 624 | [1] |
Kinetik | ||
Movement In Equity Method Interests [Roll Forward] | ||
Equity method interest, beginning balance | 0 | |
Initial interest upon closing the BCP Business Combination | 802 | |
Sale of Class A shares | (250) | |
Paid-in-kind dividend | 40 | |
Fair value adjustments | 32 | |
Equity method interest, ending balance | $ 624 | |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
EQUITY METHOD INTERESTS - Summa
EQUITY METHOD INTERESTS - Summary of Investments (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | [1] | $ 624 | $ 1,365 | |
Altus | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | 0 | $ 1,365 | $ 1,555 | |
Gulf Coast Express Pipeline LLC | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Interest | 16% | |||
Gulf Coast Express Pipeline LLC | Altus | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | 0 | $ 274 | 284 | |
EPIC Crude Holdings, LP | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Interest | 15% | |||
EPIC Crude Holdings, LP | Altus | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | 0 | $ 0 | 176 | |
Permian Highway Pipeline LLC | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Interest | 26.70% | |||
Permian Highway Pipeline LLC | Altus | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | 0 | $ 630 | 615 | |
Shin Oak Pipeline (Breviloba, LLC) | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Interest | 33% | |||
Shin Oak Pipeline (Breviloba, LLC) | Altus | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity method interests | $ 0 | $ 461 | $ 480 | |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
EQUITY METHOD INTERESTS - Rollf
EQUITY METHOD INTERESTS - Rollforward Activity (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | [1] | $ 1,365 | |||
Capital contributions | 0 | $ 28 | $ 327 | ||
Impairment | $ (160) | 0 | (160) | 0 | |
Equity method interest, ending balance | [1] | 1,365 | 624 | 1,365 | |
Altus | |||||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | 1,365 | 1,555 | |||
Capital contributions | 2 | 28 | |||
Distributions | (21) | (173) | |||
Equity income (loss), net | 21 | 114 | |||
Accumulated other comprehensive loss | 1 | ||||
Impairment | (160) | ||||
Deconsolidation of Altus | (1,367) | ||||
Equity method interest, ending balance | 1,365 | 0 | 1,365 | 1,555 | |
Gulf Coast Express Pipeline LLC | Altus | |||||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | 274 | 284 | |||
Capital contributions | 0 | 0 | |||
Distributions | (5) | (50) | |||
Equity income (loss), net | 8 | 40 | |||
Accumulated other comprehensive loss | 0 | ||||
Impairment | 0 | ||||
Deconsolidation of Altus | (277) | ||||
Equity method interest, ending balance | 274 | 0 | 274 | 284 | |
EPIC Crude Holdings, LP | Altus | |||||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | 0 | 176 | |||
Capital contributions | 2 | 2 | |||
Distributions | 0 | 0 | |||
Equity income (loss), net | (2) | (19) | |||
Accumulated other comprehensive loss | 1 | ||||
Impairment | (160) | ||||
Deconsolidation of Altus | 0 | ||||
Equity method interest, ending balance | 0 | 0 | 0 | 176 | |
Permian Highway Pipeline LLC | Altus | |||||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | 630 | 615 | |||
Capital contributions | 0 | 26 | |||
Distributions | (9) | (74) | |||
Equity income (loss), net | 10 | 63 | |||
Accumulated other comprehensive loss | 0 | ||||
Impairment | 0 | ||||
Deconsolidation of Altus | (631) | ||||
Equity method interest, ending balance | 630 | 0 | 630 | 615 | |
Shin Oak Pipeline (Breviloba, LLC) | Altus | |||||
Movement In Equity Method Interests [Roll Forward] | |||||
Equity method interest, beginning balance | 461 | 480 | |||
Capital contributions | 0 | 0 | |||
Distributions | (7) | (49) | |||
Equity income (loss), net | 5 | 30 | |||
Accumulated other comprehensive loss | 0 | ||||
Impairment | 0 | ||||
Deconsolidation of Altus | (459) | ||||
Equity method interest, ending balance | $ 461 | $ 0 | $ 461 | $ 480 | |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
OTHER CURRENT LIABILITIES (Deta
OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Payables and Accruals [Abstract] | |||
Accrued operating expenses | $ 139 | $ 129 | |
Accrued exploration and development | 300 | 206 | |
Accrued compensation and benefits | 514 | 292 | |
Accrued interest | 96 | 107 | |
Accrued income taxes | 90 | 28 | |
Current asset retirement obligation | 55 | 41 | |
Current operating lease liability | 167 | 99 | |
Current decommissioning contingency for sold Gulf of Mexico properties | 450 | 100 | |
Other | 238 | 168 | |
Total Other current liabilities | [1] | $ 2,049 | $ 1,170 |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
ASSET RETIREMENT OBLIGATION - S
ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligation at beginning of the year | $ 2,130 | $ 1,944 | |
Liabilities incurred | 4 | 3 | |
Liabilities divested | (73) | (44) | |
Liabilities settled | (39) | (32) | |
Accretion expense | 117 | 113 | |
Revisions in estimated liabilities | (148) | 146 | |
Asset retirement obligation at end of the year | 1,991 | 2,130 | |
Less current portion | (55) | (41) | |
Asset retirement obligation, long-term | [1] | $ 1,936 | $ 2,089 |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
ASSET RETIREMENT OBLIGATION - A
ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Additional abandonment liabilities associated with its drilling and development program | $ 4 | $ 3 |
Revisions in estimated liabilities | $ (148) | $ 146 |
DEBT AND FINANCING COSTS - Addi
DEBT AND FINANCING COSTS - Additional Information (Details) | 3 Months Ended | 12 Months Ended | |||||||||||||||
Oct. 17, 2022 USD ($) | Apr. 29, 2022 USD ($) option agreement | Jan. 18, 2022 USD ($) | Nov. 03, 2020 USD ($) | Aug. 18, 2020 USD ($) | Sep. 30, 2022 USD ($) | Mar. 31, 2022 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Dec. 31, 2022 GBP (£) | Apr. 29, 2022 GBP (£) agreement | Dec. 31, 2021 GBP (£) | Sep. 30, 2021 USD ($) | Aug. 17, 2020 USD ($) | Dec. 31, 2018 | Nov. 30, 2018 USD ($) | |
Debt Instrument [Line Items] | |||||||||||||||||
Loss (gain) from extinguishment of debt | $ 67,000,000 | $ 104,000,000 | $ (160,000,000) | ||||||||||||||
Current maturities | 2,000,000 | 215,000,000 | |||||||||||||||
Number of unsecured guaranties of obligations | agreement | 2 | 2 | |||||||||||||||
Debt issuance costs | 28,000,000 | 39,000,000 | |||||||||||||||
Discount of debt amortization | 2,000,000 | 6,000,000 | 7,000,000 | ||||||||||||||
APA Corp | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Number of credit agreements | agreement | 2 | 2 | |||||||||||||||
Altus credit facility | Revolving Credit Facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit facility maximum borrowing capacity | $ 800,000,000 | ||||||||||||||||
Line of credit outstanding | 657,000,000 | ||||||||||||||||
Letters of credit outstanding, amount | 2,000,000 | ||||||||||||||||
2.625% notes due 2023 | Senior Notes | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt interest rate | 2.625% | ||||||||||||||||
Current maturities | $ 123,000,000 | ||||||||||||||||
Redemption price, percentage of principal amount redeemed | 100% | ||||||||||||||||
Uncommitted Lines of Credit | Line of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit outstanding | 0 | 0 | |||||||||||||||
Uncommitted Lines of Credit | Line of Credit | Letter of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Letters of credit outstanding, amount | 17,000,000 | 17,000,000 | £ 199,000,000 | £ 117,000,000 | |||||||||||||
USD agreement | Base Rate | Maximum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 0.675% | ||||||||||||||||
USD agreement | Base Rate | Minimum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 0.10% | ||||||||||||||||
USD agreement | SOFR | Maximum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 1.675% | ||||||||||||||||
USD agreement | SOFR | Minimum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 1.10% | ||||||||||||||||
USD agreement | Line of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt term | 5 years | ||||||||||||||||
Line of credit facility, committed amount | $ 1,800,000,000 | ||||||||||||||||
Increased committed amount | $ 2,300,000,000 | ||||||||||||||||
Line of credit facility, number of extension options | option | 2 | ||||||||||||||||
Line of credit facility, extension term | 1 year | ||||||||||||||||
USD agreement | Line of Credit | Letter of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit facility maximum borrowing capacity | $ 750,000,000 | ||||||||||||||||
Current borrowing capacity | 150,000,000 | ||||||||||||||||
Maximum amount outstanding | $ 300,000,000 | ||||||||||||||||
Letters of credit outstanding, amount | 20,000,000 | ||||||||||||||||
GBP agreement | Line of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt term | 5 years | ||||||||||||||||
Line of credit facility, committed amount | £ | £ 1,500,000,000 | ||||||||||||||||
Line of credit facility, extension term | 1 year | ||||||||||||||||
GBP agreement | Line of Credit | Letter of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit facility, number of extension options | option | 2 | ||||||||||||||||
Letters of credit outstanding, amount | £ | £ 652,000,000 | ||||||||||||||||
Former facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit outstanding | 542,000,000 | ||||||||||||||||
Former facility | Revolving Credit Facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit facility, terminated amount | $ 4,000,000,000 | ||||||||||||||||
Covenant term, benchmark amount | $ 1,000,000,000 | ||||||||||||||||
Former facility | Line of Credit | Letter of Credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Letters of credit outstanding, amount | 20,000,000 | £ 748,000,000 | |||||||||||||||
Syndicated Credit Facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit outstanding | 0 | 542,000,000 | |||||||||||||||
Syndicated Credit Facility | APA Corp | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Line of credit outstanding | $ 566,000,000 | ||||||||||||||||
Syndicated Credit Facility | Revolving Credit Facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Quarterly facility fees at per annum rate | 0.275% | ||||||||||||||||
Maximum potential lien on assets located in specified regions | $ 1,500,000,000 | ||||||||||||||||
Syndicated Credit Facility | Revolving Credit Facility | Maximum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt-to-capital ratio | 0.21 | 0.21 | 0.60 | ||||||||||||||
Percentage of liens of companies consolidated asset | 15% | 15% | |||||||||||||||
Syndicated Credit Facility | Revolving Credit Facility | Base Rate | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 0.60% | ||||||||||||||||
Syndicated Credit Facility | Revolving Credit Facility | SOFR | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Margin percentage | 1.60% | ||||||||||||||||
Senior Notes | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt repurchased principle amount | $ 644,000,000 | 588,000,000 | $ 1,250,000,000 | ||||||||||||||
Debt repurchase price | 644,000,000 | 428,000,000 | |||||||||||||||
Discount to par of debt repurchase | 38,000,000 | 168,000,000 | |||||||||||||||
Debt instrument, repurchase early tender premium | 32,000,000 | ||||||||||||||||
Debt repurchase, accrued and unpaid interest | 6,000,000 | ||||||||||||||||
Loss (gain) from extinguishment of debt | $ (2,000,000) | $ (158,000,000) | |||||||||||||||
Senior Notes | Debt Repurchase, Cash Tender Offers | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt repurchased principle amount | $ 1,100,000,000 | $ 1,700,000,000 | |||||||||||||||
Debt repurchase price | 1,200,000,000 | 1,800,000,000 | |||||||||||||||
Loss (gain) from extinguishment of debt | $ 105,000,000 | 66,000,000 | |||||||||||||||
Unamortized debt issuance costs and discount | 11,000,000 | $ 11,000,000 | |||||||||||||||
Senior Notes | Open Market Repurchase | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt repurchased principle amount | 15,000,000 | 22,000,000 | |||||||||||||||
Debt repurchase price | 16,000,000 | 20,000,000 | |||||||||||||||
Discount to par of debt repurchase | 1,000,000 | 2,000,000 | |||||||||||||||
Loss (gain) from extinguishment of debt | $ 1,000,000 | $ (1,000,000) | |||||||||||||||
Senior Notes | 4.625% Senior Notes Due In 2025 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt repurchased principle amount | $ 500,000,000 | ||||||||||||||||
Debt interest rate | 4.625% | ||||||||||||||||
Senior Notes | 4.875% Senior Notes Due In 2027 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt repurchased principle amount | $ 750,000,000 | ||||||||||||||||
Debt interest rate | 4.875% | ||||||||||||||||
Senior Notes | 3.625% notes due 2021 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt interest rate | 3.625% | ||||||||||||||||
Current maturities | $ 183,000,000 | ||||||||||||||||
Redemption price, percentage of principal amount redeemed | 100% | ||||||||||||||||
Senior Notes | 3.25% notes due 2022 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Debt interest rate | 3.25% | ||||||||||||||||
Current maturities | $ 213,000,000 | ||||||||||||||||
Redemption price, percentage of principal amount redeemed | 100% |
DEBT AND FINANCING COSTS - Sche
DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions | Oct. 17, 2022 | Jan. 18, 2022 | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 4,908 | $ 6,344 | ||
Finance lease obligations | 34 | 36 | ||
Unamortized discount | (27) | (30) | ||
Debt issuance costs | (28) | (39) | ||
Total debt | 4,887 | 7,510 | ||
Current maturities | (2) | (215) | ||
Long-term debt | 4,885 | 7,295 | ||
Syndicated Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Credit facility | 0 | 542 | ||
Notes and debentures before unamortized discount and debt issuance costs | ||||
Debt Instrument [Line Items] | ||||
Debt fair value | 4,200 | 7,100 | ||
Unsecured Debt | 3.25% notes due 2022 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | 0 | $ 213 | ||
Debt interest rate | 3.25% | 3.25% | ||
Redemption price, percentage of principal amount redeemed | 100% | |||
Unsecured Debt | 2.625% notes due 2023 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | 0 | $ 123 | ||
Debt interest rate | 2.625% | 2.625% | ||
Redemption price, percentage of principal amount redeemed | 100% | |||
Unsecured Debt | 4.625% notes due 2025 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 51 | $ 500 | ||
Debt interest rate | 4.625% | |||
Unsecured Debt | 7.7% notes due 2026 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 78 | 79 | ||
Debt interest rate | 7.70% | |||
Unsecured Debt | 7.95% notes due 2026 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 132 | 133 | ||
Debt interest rate | 7.95% | |||
Unsecured Debt | 4.875% notes due 2027 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 108 | 378 | ||
Debt interest rate | 4.875% | |||
Unsecured Debt | 4.375% notes due 2028 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 325 | 703 | ||
Debt interest rate | 4.375% | |||
Unsecured Debt | 7.75% notes due in 2029 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 235 | 235 | ||
Debt interest rate | 7.75% | |||
Unsecured Debt | 4.25% notes due 2030 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 579 | 580 | ||
Debt interest rate | 4.25% | |||
Unsecured Debt | 6.0% notes due 2037 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 443 | 443 | ||
Debt interest rate | 6% | |||
Unsecured Debt | 5.1% notes due 2040 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 1,333 | 1,333 | ||
Debt interest rate | 5.10% | |||
Unsecured Debt | 5.25% notes due 2042 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 399 | 399 | ||
Debt interest rate | 5.25% | |||
Unsecured Debt | 4.75% notes due 2043 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 428 | 428 | ||
Debt interest rate | 4.75% | |||
Unsecured Debt | 4.25% notes due 2044 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 221 | 221 | ||
Debt interest rate | 4.25% | |||
Unsecured Debt | 7.375% debentures due 2047 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 150 | 150 | ||
Debt interest rate | 7.375% | |||
Unsecured Debt | 5.35% notes due 2049 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 387 | 387 | ||
Debt interest rate | 5.35% | |||
Unsecured Debt | 7.625% debentures due 2096 | ||||
Debt Instrument [Line Items] | ||||
Long-term debt, gross | $ 39 | 39 | ||
Debt interest rate | 7.625% | |||
Line of Credit | Altus credit facility | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Credit facility | $ 0 | $ 657 |
DEBT AND FINANCING COSTS - Sc_2
DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Disclosure [Abstract] | ||
2023 | $ 0 | |
2024 | 0 | |
2025 | 51 | |
2026 | 210 | |
2027 | 108 | |
Thereafter | 4,539 | |
Notes and debentures, excluding discounts and debt issuance costs | $ 4,908 | $ 6,344 |
DEBT AND FINANCING COSTS - Comp
DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |||
Interest expense | $ 312 | $ 419 | $ 438 |
Amortization of debt issuance costs | 7 | 8 | 8 |
Capitalized interest | (1) | 0 | (12) |
Loss (gain) on extinguishment of debt | 67 | 104 | (160) |
Interest income | (9) | (8) | (7) |
Interest income from APA Corporation, net | (63) | (51) | 0 |
Financing costs, net | $ 313 | $ 472 | $ 267 |
INCOME TAXES - Income (Loss) Be
INCOME TAXES - Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
U.S. | $ 2,656 | $ 689 | $ (4,581) |
Foreign | 3,218 | 1,291 | (259) |
NET INCOME (LOSS) BEFORE INCOME TAXES | $ 5,874 | $ 1,980 | $ (4,840) |
INCOME TAXES - Total Provision
INCOME TAXES - Total Provision for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Current income taxes: | |||
Federal | $ 1 | $ 16 | $ (2) |
State | 11 | 0 | 0 |
Foreign | 1,495 | 636 | 178 |
Total current income taxes | 1,507 | 652 | 176 |
Deferred income taxes: | |||
Federal | 0 | 0 | 0 |
Foreign | 145 | (74) | (112) |
Total deferred income taxes | 145 | (74) | (112) |
Total | $ 1,652 | $ 578 | $ 64 |
INCOME TAXES - Reconciliation o
INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) at U.S. statutory rate | $ 1,234 | $ 416 | $ (1,016) |
State income tax, less federal effect | 9 | 0 | 0 |
Taxes related to foreign operations | 774 | 300 | 97 |
Tax credits | (4) | (10) | (13) |
Net change in tax contingencies | 1 | 16 | 1 |
Goodwill impairment | 0 | 0 | 35 |
Valuation allowances | (705) | (111) | 965 |
Tax adjustments attributable to BCP Business Combination | 126 | 0 | 0 |
Remeasurement of U.K. deferred tax liability | 208 | 0 | 0 |
Tax attributable to Altus Preferred Unit limited partners | 0 | (34) | (16) |
All other, net | 9 | 1 | 11 |
Total | $ 1,652 | $ 578 | $ 64 |
INCOME TAXES - Net Deferred Tax
INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Deferred tax assets: | ||||
U.S. and state net operating losses | $ 2,035 | $ 2,494 | ||
Capital losses | 357 | 647 | ||
Tax credits and other tax incentives | 26 | 24 | ||
Foreign tax credits | 2,241 | 2,241 | ||
Accrued expenses and liabilities | 145 | 152 | ||
Asset retirement obligation | 672 | 712 | ||
Property and equipment | 0 | 3 | ||
Investment in Altus Midstream LP | 0 | 64 | ||
Net interest expense limitation | 55 | 135 | ||
Lease liability | 113 | 81 | ||
Decommissioning contingency for sold Gulf of Mexico properties | 275 | 263 | ||
Other | 0 | 1 | ||
Total deferred tax assets | 5,919 | 6,817 | ||
Valuation allowance | (4,831) | (5,875) | $ (5,991) | $ (4,959) |
Net deferred tax assets | 1,088 | 942 | ||
Deferred tax liabilities: | ||||
Equity investments | 1 | 2 | ||
Property and equipment | 1,014 | 748 | ||
Right-of-use asset | 110 | 77 | ||
Decommissioning security for sold Gulf of Mexico properties | 148 | 164 | ||
Other | 90 | 86 | ||
Total deferred tax liabilities | 1,363 | 1,077 | ||
Net deferred income tax liability | $ 275 | $ 135 |
INCOME TAXES - Net Deferred T_2
INCOME TAXES - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Assets: | |||
Deferred charges and other | $ 39 | $ 13 | |
Liabilities: | |||
Income taxes | [1] | 314 | 148 |
Net deferred income tax liability | $ 275 | $ 135 | |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
INCOME TAXES - Summary of Valua
INCOME TAXES - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Increase (decrease) of valuation allowances | $ (1,000) | $ (116) | $ 1,000 |
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward] | |||
Balance at beginning of year | 5,875 | 5,991 | 4,959 |
State | (111) | 1 | 67 |
U.S. | (706) | (112) | 960 |
Foreign | (227) | (5) | 5 |
Balance at end of year | $ 4,831 | $ 5,875 | $ 5,991 |
INCOME TAXES - Net Operating Lo
INCOME TAXES - Net Operating Losses (Details) $ in Millions | Dec. 31, 2022 USD ($) |
U.S. | |
Schedule Of Income Tax [Line Items] | |
Net operating losses | $ 7,968 |
State | |
Schedule Of Income Tax [Line Items] | |
Net operating losses | $ 6,505 |
INCOME TAXES - Additional Infor
INCOME TAXES - Additional Information (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Mar. 11, 2022 | Jan. 14, 2022 | Mar. 31, 2022 | Mar. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax [Line Items] | |||||||
Number of shares issued in transaction (in shares) | 4 | ||||||
Tax adjustments attributable to BCP Business Combination | $ 126 | $ 0 | $ 0 | ||||
Net interest expense carryforward | 246 | ||||||
Capital losses | 357 | 647 | |||||
Foreign tax credit carryforward, amount | 2,241 | 2,241 | |||||
Tax expense recorded for interest and penalties | 1 | 1 | 1 | ||||
Accrued for payment of interest and penalties | 5 | 4 | 3 | ||||
Increase (decrease) of reserve for uncertain tax positions | (27) | $ 23 | $ 11 | ||||
Kinetik | |||||||
Income Tax [Line Items] | |||||||
Number of shares issued in transaction (in shares) | 4 | 4 | |||||
Canada | |||||||
Income Tax [Line Items] | |||||||
Deferred tax expense, remeasurement of deferred tax liability | 208 | ||||||
Canada | Minimum | Scenario, Forecast | |||||||
Income Tax [Line Items] | |||||||
Deferred tax expense, remeasurement of deferred tax liability | $ 170 | ||||||
Canada | Maximum | Scenario, Forecast | |||||||
Income Tax [Line Items] | |||||||
Deferred tax expense, remeasurement of deferred tax liability | $ 190 | ||||||
U.S. | |||||||
Income Tax [Line Items] | |||||||
Operating loss carryforwards | 7,968 | ||||||
Operating loss carryforwards subject to annual limitation | 82 | ||||||
Capital losses | $ 1,600 | ||||||
Capital loss carryforward carryover period | 5 years | ||||||
State | |||||||
Income Tax [Line Items] | |||||||
Operating loss carryforwards | $ 6,505 | ||||||
BCP Business Combination | |||||||
Income Tax [Line Items] | |||||||
Tax adjustments attributable to BCP Business Combination | $ 126 | ||||||
Apache Midstream LLC | |||||||
Income Tax [Line Items] | |||||||
Stock exchanged during period (in shares) | 12.5 | ||||||
Altus | |||||||
Income Tax [Line Items] | |||||||
Stock exchanged during period (in shares) | 12.5 |
INCOME TAXES - Schedule of Fore
INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Income Tax Disclosure [Abstract] | ||
Foreign tax credit carryforward, amount | $ 2,241 | $ 2,241 |
INCOME TAXES - Reconciliation_2
INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance at beginning of year | $ 116 | $ 93 | $ 82 |
Additions based on tax positions related to prior year | 0 | 16 | 0 |
Additions based on tax positions related to the current year | 0 | 7 | 11 |
Reductions for tax positions of prior years | (27) | 0 | 0 |
Balance at end of year | $ 89 | $ 116 | $ 93 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions | 12 Months Ended | |||||||||||||
Sep. 10, 2020 defendant | Sep. 11, 2019 USD ($) plaintiff | Dec. 20, 2017 Action | Jul. 17, 2017 Action defendant | Mar. 21, 2016 USD ($) | Mar. 20, 2016 USD ($) | Dec. 31, 2022 USD ($) subsidiary bond | Dec. 31, 2021 USD ($) sidetrack | Dec. 31, 2020 USD ($) | Dec. 31, 2013 USD ($) source | Dec. 31, 2017 AUD ($) | Apr. 30, 2017 AUD ($) | Mar. 12, 2014 USD ($) | ||
Commitment And Contingencies [Line Items] | ||||||||||||||
Accrued liability for legal contingencies | $ 64,000,000 | |||||||||||||
Environmental tax and royalty obligations | $ 100,000,000 | |||||||||||||
Retain right of obligations | 45,000,000 | |||||||||||||
Number of plaintiffs | plaintiff | 4 | |||||||||||||
Maximum cost considered to be recognized for additional reserve | 300,000 | |||||||||||||
Undiscounted reserve for environmental remediation | 1,000,000 | |||||||||||||
Standby loan agreed to provide related to ARO | 400,000,000 | |||||||||||||
Decommissioning contingency for sold properties, total | 1,200,000,000 | |||||||||||||
Decommissioning contingency for sold Gulf of Mexico properties (Note 12) | [1] | 738,000,000 | $ 1,086,000,000 | |||||||||||
Current decommissioning contingency for sold Gulf of Mexico properties | 450,000,000 | 100,000,000 | ||||||||||||
Decommissioning security for sold Gulf of Mexico properties, total | 667,000,000 | |||||||||||||
Decommissioning security for sold Gulf of Mexico properties (Note 12) | [1] | 217,000,000 | 640,000,000 | |||||||||||
Current decommissioning security for sold Gulf of Mexico assets | 450,000,000 | 100,000,000 | ||||||||||||
Losses on previously sold Gulf of Mexico properties | 157,000,000 | 446,000,000 | $ 0 | |||||||||||
Fixed operating lease expenses | 144,000,000 | 127,000,000 | 149,000,000 | |||||||||||
Depreciation on finance lease asset | 2,000,000 | 2,000,000 | 2,000,000 | |||||||||||
Interest on finance lease asset | 2,000,000 | 2,000,000 | 2,000,000 | |||||||||||
Variable lease payment | 89,000,000 | $ 63,000,000 | $ 41,000,000 | |||||||||||
Undiscounted commitments for operating leases not yet commenced | $ 207,000,000 | |||||||||||||
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | Current debt | Current debt | ||||||||||||
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | LONG-TERM DEBT (Note 10) ($657 related to Altus VIE) | LONG-TERM DEBT (Note 10) ($657 related to Altus VIE) | ||||||||||||
Apollo Exploration Lawsuit | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Loss contingency damages sought value | $ 200,000,000 | |||||||||||||
Canadian Operations Divestiture Dispute | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Loss contingency punitive damages | $ 60,000,000 | |||||||||||||
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 | |||||||||||||
Castex Lawsuit | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Loss contingency damages sought value | $ 200,000,000 | |||||||||||||
Loss contingency estimate of possible loss | $ 13,500,000 | $ 60,000,000 | ||||||||||||
Number of sidetracks | sidetrack | 5 | |||||||||||||
Apache Australia Operation | Australian Operations Divestiture Dispute | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Gain contingency, unrecorded amount | $ 80 | |||||||||||||
Loss contingency estimate of possible loss | $ 200 | |||||||||||||
Gulf Of Mexico Shelf Operations And Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||||||||||||
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 | source | 2 | |||||||||||||
Number of bonds held | bond | 2 | |||||||||||||
Number of debt instruments held | subsidiary | 5 | |||||||||||||
Minimum | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Asset retirement obligation, estimated liability | $ 1,200,000,000 | |||||||||||||
Minimum | Apollo Exploration Lawsuit | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Loss contingency damages sought value | $ 1,100,000,000 | |||||||||||||
Maximum | ||||||||||||||
Commitment And Contingencies [Line Items] | ||||||||||||||
Asset retirement obligation, estimated liability | $ 1,400,000,000 | |||||||||||||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details) | Dec. 31, 2022 |
Accounting Policies [Abstract] | |
Operating leases, weighted average remaining lease term | 2 years 6 months |
Finance leases, weighted average remaining lease term | 10 years 8 months 12 days |
Operating leases, weighted average discount rate | 3.70% |
Finance leases, weighted average discount rate | 4.40% |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Leases | |||
2023 | $ 174 | ||
2024 | 102 | ||
2025 | 14 | ||
2026 | 6 | ||
2027 | 6 | ||
Thereafter | 11 | ||
Total future minimum payments | 313 | ||
Less: imputed interest | (14) | ||
Total lease liabilities | 299 | ||
Current portion | 167 | $ 99 | |
Non-current portion | $ 132 | ||
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other current liabilities (Note 8) ($15 related to Altus VIE) | Other current liabilities (Note 8) ($15 related to Altus VIE) | |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other ($67 related to Altus VIE) | Other ($67 related to Altus VIE) | |
Finance Leases | |||
2023 | $ 3 | ||
2024 | 3 | ||
2025 | 4 | ||
2026 | 4 | ||
2027 | 4 | ||
Thereafter | 27 | ||
Total future minimum payments | 45 | ||
Less: imputed interest | (11) | ||
Total lease liabilities | 34 | $ 36 | |
Current portion | 2 | ||
Non-current portion | 32 | ||
Purchase Obligations | |||
2023 | 222 | ||
2024 | 183 | ||
2025 | 163 | ||
2026 | 1,951 | ||
2027 | 133 | ||
Thereafter | 333 | ||
Total future minimum payments | 2,985 | ||
Total costs under take or pay and throughout obligation | 183 | $ 194 | $ 120 |
Purchase commitment, remaining minimum amount committed | 3,500 | ||
Purchase commitment, amount incurred | $ 1,700 |
RETIREMENT AND DEFERRED COMPE_3
RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Portion of employee's salary, employee contributions under non-qualified retirement savings plan | 50% | ||
Maximum percentage of compensation contributed by the company | 8% | ||
Percentage of additional contribution to money purchase retirement plan | 6% | ||
Maximum percentage of eligible compensation contributed by the participating employees | 50% | ||
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested | 75% | ||
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested | 20% | ||
Annual cost of retirement benefit plans | $ 40 | $ 31 | $ 43 |
Targeted ongoing funding level of pension plan policy, percent | 100% | ||
Outperformance relative to gilts for equities | 3.50% | ||
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Accumulated benefit obligation for pension plans | $ 89 | $ 205 | $ 207 |
Expected contribution towards pension and postretirement plan | 2 | ||
Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected contribution towards pension and postretirement plan | $ 3 |
RETIREMENT AND DEFERRED COMPE_4
RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | $ 254 | ||
Fair value of plan assets at end of year | 137 | $ 254 | |
Pension Benefits | |||
Change in Projected Benefit Obligation | |||
Projected benefit obligation at beginning of year | 211 | 233 | $ 199 |
Service cost | 2 | 3 | 3 |
Interest cost | 3 | 3 | 4 |
Foreign currency exchange rates | (21) | (2) | 8 |
Actuarial losses (gains) | (79) | (5) | 30 |
Plan settlements | 0 | (17) | 0 |
Benefits paid | (8) | (4) | (11) |
Retiree contributions | 0 | 0 | 0 |
Projected benefit obligation at end of year | 108 | 211 | 233 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 254 | 262 | 228 |
Actual return (loss) on plan assets | (87) | 11 | 31 |
Foreign currency exchange rates | (26) | (3) | 9 |
Employer contributions | 4 | 5 | 5 |
Plan settlements | 0 | (17) | 0 |
Benefits paid | (8) | (4) | (11) |
Retiree contributions | 0 | 0 | 0 |
Fair value of plan assets at end of year | 137 | 254 | 262 |
Funded status at end of year | 29 | 43 | 29 |
Amounts recognized in Consolidated Balance Sheet | |||
Current liability | 0 | 0 | 0 |
Non-current asset | 29 | 43 | 29 |
Amounts recognized in Consolidated Balance Sheet | 29 | 43 | 29 |
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) | |||
Accumulated gain (loss) | $ (10) | $ 1 | $ (11) |
Weighted Average Assumptions used as of December 31 | |||
Discount rate | 5% | 1.80% | 1.40% |
Salary increases | 4.70% | 4.90% | 4.50% |
Expected return on assets | 4.70% | 1.90% | 1.50% |
Postretirement Benefits | |||
Change in Projected Benefit Obligation | |||
Projected benefit obligation at beginning of year | $ 20 | $ 20 | $ 20 |
Service cost | 1 | 1 | 1 |
Interest cost | 0 | 0 | 0 |
Foreign currency exchange rates | 0 | 0 | 0 |
Actuarial losses (gains) | (5) | 1 | 1 |
Plan settlements | 0 | 0 | 0 |
Benefits paid | (3) | (4) | (4) |
Retiree contributions | 2 | 2 | 2 |
Projected benefit obligation at end of year | 15 | 20 | 20 |
Change in Plan Assets | |||
Fair value of plan assets at beginning of year | 0 | 0 | 0 |
Actual return (loss) on plan assets | 0 | 0 | 0 |
Foreign currency exchange rates | 0 | 0 | 0 |
Employer contributions | 2 | 2 | 2 |
Plan settlements | 0 | 0 | 0 |
Benefits paid | (4) | (4) | (4) |
Retiree contributions | 2 | 2 | 2 |
Fair value of plan assets at end of year | 0 | 0 | 0 |
Funded status at end of year | (15) | (20) | (20) |
Amounts recognized in Consolidated Balance Sheet | |||
Current liability | (2) | (2) | (2) |
Non-current liability | (13) | (18) | (18) |
Amounts recognized in Consolidated Balance Sheet | (15) | (20) | (20) |
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss) | |||
Accumulated gain (loss) | $ 18 | $ 14 | $ 16 |
Weighted Average Assumptions used as of December 31 | |||
Discount rate | 5.29% | 2.57% | 2.06% |
Healthcare cost trend | |||
Initial | 6.50% | 6.25% | 6% |
Ultimate in 2028 | 5.25% | 5% | 5% |
RETIREMENT AND DEFERRED COMPE_5
RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details) | Dec. 31, 2022 | Dec. 31, 2021 |
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 100% | |
Percentage of Plan Assets at Year-End | 100% | 100% |
Equity securities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 14% | |
Percentage of Plan Assets at Year-End | 15% | 15% |
Overseas quoted equities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 14% | |
Percentage of Plan Assets at Year-End | 15% | 15% |
Debt securities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 84% | |
Percentage of Plan Assets at Year-End | 84% | 79% |
U.K. government bonds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 52% | |
Percentage of Plan Assets at Year-End | 52% | 54% |
U.K. corporate bonds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 32% | |
Percentage of Plan Assets at Year-End | 32% | 25% |
Cash | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Allocation | 2% | |
Percentage of Plan Assets at Year-End | 1% | 6% |
RETIREMENT AND DEFERRED COMPE_6
RETIREMENT AND DEFERRED COMPENSATION PLANS - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | $ 137 | $ 254 |
Equity securities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 20 | 38 |
Overseas quoted equities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 20 | 38 |
Debt securities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 115 | 200 |
U.K. government bonds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 71 | 138 |
U.K. corporate bonds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 44 | 62 |
Cash | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | $ 2 | $ 16 |
RETIREMENT AND DEFERRED COMPE_7
RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 | |||
Salary increases | 4.90% | 4.50% | 4.30% |
Expected return on assets | 1.90% | 1.50% | 2.20% |
Pension Benefits | |||
Components of Net Periodic Benefit Cost | |||
Service cost | $ 2 | $ 3 | $ 3 |
Interest cost | 3 | 3 | 4 |
Expected return on assets | (4) | (4) | (5) |
Amortization of loss | 0 | 0 | 0 |
Settlement loss | 0 | 0 | 0 |
Net periodic benefit cost | $ 1 | $ 2 | $ 2 |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 | |||
Discount rate | 1.80% | 1.40% | 2.10% |
Postretirement Benefits | |||
Components of Net Periodic Benefit Cost | |||
Service cost | $ 1 | $ 1 | $ 1 |
Interest cost | 0 | 0 | 0 |
Expected return on assets | 0 | 0 | 0 |
Amortization of loss | (1) | (1) | (1) |
Settlement loss | 0 | 0 | 0 |
Net periodic benefit cost | $ 0 | $ 0 | $ 0 |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31 | |||
Discount rate | 2.57% | 2.06% | 3% |
Healthcare cost trend | |||
Initial | 6.25% | 6% | 6.25% |
Ultimate in 2028 | 5% | 5% | 5% |
RETIREMENT AND DEFERRED COMPE_8
RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
2023 | $ 5 |
2024 | 5 |
2025 | 5 |
2026 | 5 |
2027 | 5 |
Years 2028-2032 | 28 |
Postretirement Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
2023 | 2 |
2024 | 2 |
2025 | 2 |
2026 | 1 |
2027 | 1 |
Years 2028-2032 | $ 6 |
REDEMABLE NONCONTROLLING INTE_3
REDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | |
Jun. 12, 2019 | Mar. 31, 2022 | |
Class of Stock [Line Items] | ||
Aggregate issue price of preferred units | $ 224 | |
Altus Midstream LP | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners | ||
Class of Stock [Line Items] | ||
Aggregate issue price of preferred units | $ 625 | |
Proceeds from issuance or sale of equity | $ 611 |
REDEMABLE NONCONTROLLING INTE_4
REDEMABLE NONCONTROLLING INTEREST - ALTUS - Activity Related to Preferred Units (Details) - USD ($) $ in Millions | 2 Months Ended | 12 Months Ended | ||||||
Feb. 22, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Nov. 30, 2022 | ||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||
Beginning balance | $ 712 | [1] | $ 712 | [1] | $ 608 | $ 555 | ||
Distributions paid to Altus Preferred Unit limited partners | (46) | (23) | ||||||
Distributions payable to Altus Preferred Unit limited partners | (12) | |||||||
Ending balance | 0 | [1] | 712 | [1] | $ 608 | |||
Preferred Units embedded derivative | $ 0 | $ 113 | $ 37 | |||||
Altus Midstream LP | ||||||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||
Preferred Units embedded derivative | 89 | |||||||
Deconsolidation of Altus | (731) | |||||||
Redeemable noncontrolling interest, net of embedded derivative liability | $ 0 | |||||||
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners | Altus Midstream LP | ||||||||
Movement In Preferred Units [Roll Forward] | ||||||||
Preferred Units: beginning of period (in shares) | 660,694 | 660,694 | 660,694 | |||||
Preferred Units: end of period (in shares) | 660,694 | 660,694 | 660,694 | |||||
Increase (Decrease) in Temporary Equity [Roll Forward] | ||||||||
Beginning balance | $ 712 | $ 712 | $ 608 | |||||
Distributions paid to Altus Preferred Unit limited partners | $ (46) | |||||||
Distributions payable to Altus Preferred Unit limited partners | (12) | |||||||
Allocation of Altus Midstream net income | 12 | 80 | ||||||
Accreted value adjustment | (82) | 82 | ||||||
Ending balance | $ 642 | $ 712 | $ 608 | |||||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
CAPITAL STOCK AND EQUITY - Addi
CAPITAL STOCK AND EQUITY - Additional Information (Details) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2023 USD ($) $ / shares shares | Dec. 31, 2022 USD ($) $ / shares shares | Dec. 31, 2021 USD ($) $ / shares shares | Dec. 31, 2020 USD ($) $ / shares shares | Mar. 01, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Common stock, conversion ratio | 1 | ||||
Shares authorized and available for grant (in shares) | shares | 10,100,000 | ||||
Shares Issued in the period (in shares) | shares | 0 | 0 | 0 | ||
Shares exercised in the period (in shares) | shares | (98,646) | 0 | 0 | ||
Stock-settled and cash-settled compensation expensed | $ 288 | $ 152 | $ 40 | ||
Stock-settled and cash-settled compensation capitalized | $ 43 | 18 | 7 | ||
Stock Option | In or after 2016 | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Period in which stock options become exercisable | 3 years | ||||
Period in which stock options expires after grant date | 10 years | ||||
Restricted Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-settled and cash-settled compensation expensed | $ 145 | 91 | 39 | ||
Stock-settled and cash-settled compensation capitalized | $ 22 | $ 15 | $ 6 | ||
Awards granted during period (in shares) | shares | 847,000 | 1,506,000 | 1,352,000 | ||
Weighted average grant date fair value per share (in USD per share) | $ / shares | $ 29.90 | $ 16.46 | $ 24.60 | ||
Total compensation cost related to non-vested awards not yet recognized | $ 14 | ||||
Restricted Stock | Subsequent Event | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Period in which stock options become exercisable | 3 years | ||||
Awards granted during period (in shares) | shares | 580,254 | ||||
Weighted average grant date fair value per share (in USD per share) | $ / shares | $ 42.15 | ||||
Total compensation cost related to non-vested awards not yet recognized | $ 24 | ||||
Phantom Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards granted during period (in shares) | shares | 2,568,000 | 4,441,000 | 3,462,000 | ||
Total compensation cost related to non-vested awards not yet recognized | $ 103 | ||||
Phantom Units | Subsequent Event | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Awards granted during period (in shares) | shares | 1,950,332 | ||||
Total compensation cost related to non-vested awards not yet recognized | $ 85 |
CAPITAL STOCK AND EQUITY - Desc
CAPITAL STOCK AND EQUITY - Description of Stock Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Equity [Abstract] | |||
Stock-settled and cash-settled compensation expensed | $ 288 | $ 152 | $ 40 |
Stock-settled and cash-settled compensation capitalized | 43 | 18 | 7 |
Total stock-settled and cash-settled compensation costs | $ 331 | $ 170 | $ 47 |
CAPITAL STOCK AND EQUITY - Summ
CAPITAL STOCK AND EQUITY - Summary of Stock Options Activities (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Outstanding, beginning of year, Shares (in shares) | 3,012,000 | 3,537,000 | 4,298,000 |
Exercised, Shares (in shares) | (98,646) | 0 | 0 |
Forfeited, Shares (in shares) | (2,000) | 0 | (37,000) |
Expired, Shares (in shares) | (833,000) | (525,000) | (724,000) |
Outstanding, end of year, Shares (in shares) | 2,078,000 | 3,012,000 | 3,537,000 |
Expected to vest, Shares (in shares) | 0 | 0 | 150,000 |
Exercisable, end of year, Shares (in shares) | 2,078,000 | 3,012,000 | 3,387,000 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract] | |||
Outstanding, beginning of year, weighted average exercise price (in USD per share) | $ 63.79 | $ 72.10 | $ 75.24 |
Exercised, weighted average exercise price (in USD per share) | 42.09 | 0 | 0 |
Forfeited, weighted average exercise price (in USD per share) | 49.10 | 0 | 44.98 |
Expired, weighted average exercise price (in USD per share) | 81.56 | 119.83 | 92.14 |
Outstanding, end of year, weighted average exercise price (in USD per share) | 57.71 | 63.79 | 72.10 |
Expected to vest, weighted average exercise price (in USD per share) | 0 | 0 | 45.77 |
Exercisable, end of year, weighted average exercise price (in USD per share) | $ 57.71 | $ 63.79 | $ 73.26 |
Weighted average remaining contractual life for options outstanding | 3 years 1 month 6 days | ||
Aggregate intrinsic value for options outstanding | $ 3.5 |
CAPITAL STOCK AND EQUITY - Sche
CAPITAL STOCK AND EQUITY - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Weighted Average Grant-Date Fair Value | |||
Unvested restricted stock units (in shares) | 1,885,491 | ||
Weighted-average remaining life of unvested restricted stock units | 8 months 12 days | ||
Total fair value of restricted stock awards vested | $ 22 | $ 25 | $ 94 |
Restricted Stock | |||
Units | |||
Non-vested, beginning balance (in shares) | 2,073,000 | 1,552,000 | 2,448,000 |
Granted, Shares (in shares) | 847,000 | 1,506,000 | 1,352,000 |
Vested, Shares (in shares) | (978,000) | (857,000) | (1,933,000) |
Forfeited, Shares (in shares) | (57,000) | (128,000) | (315,000) |
Non-vested, ending balance (in shares) | 1,885,000 | 2,073,000 | 1,552,000 |
Weighted Average Grant-Date Fair Value | |||
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ 19.98 | $ 28.43 | $ 46.65 |
Granted, Weighted Average Grant-Date Fair Value (in USD per share) | 29.90 | 16.46 | 24.60 |
Vested, Weighted Average Grant-Date Fair Value (in USD per share) | 22.39 | 29.13 | 48.65 |
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share) | 23.49 | 19.78 | 30.09 |
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share) | $ 23.08 | $ 19.98 | $ 28.43 |
Total compensation cost related to non-vested awards not yet recognized | $ 14 | ||
Phantom Units | |||
Units | |||
Non-vested, beginning balance (in shares) | 6,402,000 | 4,423,000 | 5,384,000 |
Reverse stock split (in shares) | 0 | 0 | (1,246,000) |
Reverse stock (in shares) | 143,000 | 0 | 0 |
Granted, Shares (in shares) | 2,568,000 | 4,441,000 | 3,462,000 |
Vested, Shares (in shares) | (2,970,000) | (2,049,000) | (1,618,000) |
Forfeited, Shares (in shares) | (434,000) | (413,000) | (1,559,000) |
Non-vested, ending balance (in shares) | 5,709,000 | 6,402,000 | 4,423,000 |
Weighted Average Grant-Date Fair Value | |||
Total compensation cost related to non-vested awards not yet recognized | $ 103 | ||
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock | |||
Units | |||
Granted, Shares (in shares) | 2,512,602 | 4,375,546 | 3,378,486 |
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock | |||
Units | |||
Granted, Shares (in shares) | 55,546 | 65,327 | 83,239 |
Cash-settled conditional restricted stock unit | Performance Program | |||
Units | |||
Non-vested, beginning balance (in shares) | 4,531,000 | ||
Granted, Shares (in shares) | 1,676,000 | ||
Vested, Shares (in shares) | (656,000) | ||
Forfeited, Shares (in shares) | (106,000) | ||
Non-vested, ending balance (in shares) | 4,835,000 | 4,531,000 |
CAPITAL STOCK AND EQUITY - Perf
CAPITAL STOCK AND EQUITY - Performance Program Narrative (Details) $ / shares in Units, $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | |||||||
Jan. 31, 2023 $ / shares shares | Jan. 31, 2022 shares | Jan. 31, 2021 shares | Jan. 31, 2020 shares | Jan. 31, 2019 shares | Jan. 31, 2018 shares | Jun. 30, 2020 | Dec. 31, 2022 USD ($) shares | Dec. 31, 2021 USD ($) shares | Dec. 31, 2020 USD ($) shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares authorized and available for grant (in shares) | 10,100,000 | |||||||||
Compensation expense | $ | $ 288 | $ 152 | $ 40 | |||||||
Stock-settled and cash-settled compensation capitalized | $ | $ 43 | $ 18 | $ 7 | |||||||
Altus Midstream LP | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Reverse stock split ratio | 0.05 | |||||||||
Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 2,568,000 | 4,441,000 | 3,462,000 | |||||||
Phantom Units | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 1,950,332 | |||||||||
Performance Program | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares vesting period | 3 years | |||||||||
Compensation expense | $ | $ 136 | $ 56 | $ 8 | |||||||
Stock-settled and cash-settled compensation capitalized | $ | $ 21 | $ 3 | $ 1 | |||||||
Performance Program | Vesting, Tranche One | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares vesting percentage | 50% | |||||||||
Performance Program | Vesting, Tranche Two | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares vesting percentage | 50% | |||||||||
2018 Performance Program | Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 931,049 | |||||||||
Total awards, outstanding (in shares) | 23,633 | |||||||||
Shares paid out as percentage of target | 23% | |||||||||
2019 Performance Program | Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 1,679,832 | |||||||||
Total awards, outstanding (in shares) | 604,417 | |||||||||
Shares paid out as percentage of target | 100% | |||||||||
2020 Performance Program | Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 1,687,307 | |||||||||
Total awards, outstanding (in shares) | 1,311,715 | |||||||||
Shares paid out as percentage of target | 155% | |||||||||
2021 Performance Program | Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 1,959,856 | |||||||||
Total awards, outstanding (in shares) | 1,826,890 | |||||||||
2021 Performance Program | Phantom Units | Minimum | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Percentage of shares awarded of target | 0% | |||||||||
Shares authorized and available for grant (in shares) | 0 | |||||||||
2021 Performance Program | Phantom Units | Maximum | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Percentage of shares awarded of target | 200% | |||||||||
Shares authorized and available for grant (in shares) | 3,653,780 | |||||||||
2022 Performance Program | Phantom Units | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 1,093,034 | |||||||||
Total awards, outstanding (in shares) | 1,068,530 | |||||||||
2022 Performance Program | Phantom Units | Minimum | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Percentage of shares awarded of target | 0% | |||||||||
Shares authorized and available for grant (in shares) | 0 | |||||||||
2022 Performance Program | Phantom Units | Maximum | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Percentage of shares awarded of target | 200% | |||||||||
Shares authorized and available for grant (in shares) | 2,137,060 | |||||||||
2023 Performance Program | Vesting, Tranche One | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares allocation percentage | 40% | |||||||||
Shares vesting period | 3 years | |||||||||
2023 Performance Program | Vesting, Tranche Two | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares vesting percentage | 60% | |||||||||
2023 Performance Program | Phantom Units | Vesting, Tranche One | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Weighted average grant date fair value per share (in USD per share) | $ / shares | $ 62.15 | |||||||||
2023 Performance Program | Phantom Units | Vesting, Tranche Two | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Awards granted during period (in shares) | 797,429 | |||||||||
Weighted average grant date fair value per share (in USD per share) | $ / shares | $ 44.06 | |||||||||
2023 Performance Program | Phantom Units | Minimum | Vesting, Tranche Two | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares authorized and available for grant (in shares) | 0 | |||||||||
2023 Performance Program | Phantom Units | Maximum | Vesting, Tranche Two | Subsequent Event | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares authorized and available for grant (in shares) | 1,594,858 |
CAPITAL STOCK AND EQUITY - Sc_2
CAPITAL STOCK AND EQUITY - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Weighted Average Grant-Date Fair Value | ||
Weighted-average remaining life of unvested restricted stock units | 8 months 12 days | |
Employee-related liabilities, current | $ 514 | $ 292 |
Performance Program | Cash-settled conditional restricted stock unit | ||
Units | ||
Non-vested, beginning balance (in shares) | 4,531 | |
Vested, Shares (in shares) | (656) | |
Non-vested, ending balance (in shares) | 4,835 | 4,531 |
Weighted Average Grant-Date Fair Value | ||
Employee-related liabilities, current | $ 53 | |
Awards granted during period (in shares) | 1,676 | |
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Forfeited in Period | (106) | |
Expired, Shares (in shares) | (610) |
ACCUMULATED OTHER COMPREHENSI_3
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Equity [Abstract] | |||||
Share of equity method interests other comprehensive loss | $ 0 | $ 0 | $ (1) | ||
Pension and postretirement benefit plan (Note 13) | 14 | 22 | 15 | ||
Accumulated other comprehensive income | $ 14 | [1] | $ 22 | [1] | $ 14 |
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. |
MAJOR CUSTOMERS (Details)
MAJOR CUSTOMERS (Details) - Customer Concentration Risk - Oil and Gas Production Revenues | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Egyptian General Petroleum Corporation | |||
Revenue, Major Customer [Line Items] | |||
Concentration risk percentage | 15% | 14% | |
Vitol | |||
Revenue, Major Customer [Line Items] | |||
Concentration risk percentage | 10% | ||
BP plc | |||
Revenue, Major Customer [Line Items] | |||
Concentration risk percentage | 17% | ||
China Petroleum & Chemical Corporation (Sinopec) | |||
Revenue, Major Customer [Line Items] | |||
Concentration risk percentage | 14% |
BUSINESS SEGMENT INFORMATION -
BUSINESS SEGMENT INFORMATION - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2022 Segment | |
Segment Reporting [Abstract] | |
Number of reporting segments | 3 |
BUSINESS SEGMENT INFORMATION _2
BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||||
Operating Expenses: | ||||||
Lease operating expenses | $ 1,435 | $ 1,241 | $ 1,127 | |||
Taxes other than income | 256 | 204 | 123 | |||
Exploration | 146 | 127 | 274 | |||
Depreciation, depletion, and amortization | 1,177 | 1,360 | 1,772 | |||
Asset retirement obligation accretion | 117 | 113 | 109 | |||
Impairments | 0 | 208 | 4,501 | |||
Total operating expenses | 5,263 | 5,097 | 8,537 | |||
Operating Income (Loss) | 5,620 | 2,888 | (4,102) | |||
Other Income (Expense): | ||||||
Gain on divestitures, net | 1,180 | 67 | 32 | |||
Losses on previously sold Gulf of Mexico properties | (157) | (446) | ||||
Derivative instrument losses, net | (107) | 94 | (223) | |||
Other | 139 | 228 | 64 | |||
General and administrative | (462) | (357) | (290) | |||
Transaction, reorganization, and separation | (26) | (22) | (54) | |||
Financing costs, net | (313) | (472) | (267) | |||
NET INCOME (LOSS) BEFORE INCOME TAXES | 5,874 | 1,980 | (4,840) | |||
Assets | 14,255 | [1] | 14,393 | [1] | 12,746 | |
Net Property and Equipment | 7,957 | [1] | 8,060 | [1] | 8,819 | |
Additions to Net Property and Equipment | 1,657 | 1,004 | 1,162 | |||
Operating Segments | Egypt | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 526 | 469 | 424 | |||
Taxes other than income | 0 | 0 | 0 | |||
Exploration | 84 | 63 | 63 | |||
Depreciation, depletion, and amortization | 400 | 524 | 601 | |||
Asset retirement obligation accretion | 0 | 0 | 0 | |||
Impairments | 26 | 529 | ||||
Total operating expenses | 1,032 | 1,094 | 1,655 | |||
Operating Income (Loss) | 2,489 | 991 | (265) | |||
Other Income (Expense): | ||||||
Assets | 3,148 | 2,796 | 3,003 | |||
Net Property and Equipment | 1,976 | 1,720 | 1,955 | |||
Additions to Net Property and Equipment | 695 | 319 | 454 | |||
Operating Segments | North Sea | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 404 | 383 | 305 | |||
Taxes other than income | 0 | 0 | 0 | |||
Exploration | 35 | 34 | 28 | |||
Depreciation, depletion, and amortization | 238 | 270 | 380 | |||
Asset retirement obligation accretion | 82 | 79 | 73 | |||
Impairments | 22 | 7 | ||||
Total operating expenses | 802 | 827 | 843 | |||
Operating Income (Loss) | 756 | 309 | 40 | |||
Other Income (Expense): | ||||||
Assets | 1,911 | 2,199 | 2,220 | |||
Net Property and Equipment | 1,386 | 1,646 | 1,773 | |||
Additions to Net Property and Equipment | 210 | 159 | 215 | |||
Operating Segments | U.S. | ||||||
Operating Expenses: | ||||||
Lease operating expenses | 506 | 391 | 400 | |||
Taxes other than income | 253 | 190 | 108 | |||
Exploration | 24 | 28 | 168 | |||
Depreciation, depletion, and amortization | 537 | 554 | 779 | |||
Asset retirement obligation accretion | 34 | 30 | 32 | |||
Impairments | 0 | 3,963 | ||||
Total operating expenses | 3,434 | 3,077 | 6,095 | |||
Operating Income (Loss) | 2,368 | 1,679 | (3,937) | |||
Other Income (Expense): | ||||||
Assets | 9,196 | 7,700 | 5,540 | |||
Net Property and Equipment | 4,595 | 4,507 | 4,760 | |||
Additions to Net Property and Equipment | 752 | 523 | 345 | |||
Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 16 | 127 | 145 | |||
Operating Expenses: | ||||||
Lease operating expenses | 0 | 0 | 0 | |||
Taxes other than income | 3 | 14 | 15 | |||
Exploration | 0 | 0 | 0 | |||
Depreciation, depletion, and amortization | 2 | 12 | 12 | |||
Asset retirement obligation accretion | 1 | 4 | 4 | |||
Impairments | 160 | 2 | ||||
Total operating expenses | 11 | 227 | 74 | |||
Operating Income (Loss) | 10 | (89) | 75 | |||
Other Income (Expense): | ||||||
Assets | 0 | 1,698 | 1,786 | |||
Net Property and Equipment | 0 | 187 | 196 | |||
Additions to Net Property and Equipment | 0 | 3 | 12 | |||
Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | (16) | (127) | (145) | |||
Operating Expenses: | ||||||
Lease operating expenses | (1) | (2) | (2) | |||
Taxes other than income | 0 | 0 | 0 | |||
Exploration | 3 | 2 | 15 | |||
Depreciation, depletion, and amortization | 0 | 0 | 0 | |||
Asset retirement obligation accretion | 0 | 0 | 0 | |||
Impairments | 0 | 0 | ||||
Total operating expenses | (16) | (128) | (130) | |||
Operating Income (Loss) | (3) | (2) | (15) | |||
Other Income (Expense): | ||||||
Assets | 0 | 0 | 197 | |||
Net Property and Equipment | 0 | 0 | 135 | |||
Additions to Net Property and Equipment | 0 | 0 | 136 | |||
Oil and gas, excluding purchased | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | [2] | 9,028 | 6,498 | 4,037 | ||
Operating Expenses: | ||||||
Gathering, processing, and transmission | [2] | 356 | 264 | 274 | ||
Oil and gas, excluding purchased | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 3,521 | 2,085 | 1,390 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 22 | 12 | 38 | |||
Oil and gas, excluding purchased | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 1,558 | 1,136 | 883 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 43 | 39 | 50 | |||
Oil and gas, excluding purchased | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 3,952 | 3,280 | 1,764 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 304 | 309 | 291 | |||
Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 5 | 32 | 38 | |||
Oil and gas, excluding purchased | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | (3) | (3) | 0 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | (18) | (128) | (143) | |||
Oil and gas, purchased | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 1,855 | 1,487 | 398 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 1,776 | 1,580 | 357 | |||
Oil and gas, purchased | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 0 | 0 | 0 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 0 | 0 | 0 | |||
Oil and gas, purchased | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 0 | 0 | 0 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 0 | 0 | 0 | |||
Oil and gas, purchased | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 1,850 | 1,476 | 394 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 1,776 | 1,575 | 354 | |||
Oil and gas, purchased | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 5 | 11 | 4 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 0 | 5 | 3 | |||
Oil and gas, purchased | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil and gas production revenues | 0 | 0 | 0 | |||
Operating Expenses: | ||||||
Gathering, processing, and transmission | 0 | 0 | 0 | |||
Oil and gas | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 10,883 | 7,985 | 4,435 | |||
Oil and gas | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 3,521 | 2,085 | 1,390 | |||
Oil and gas | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 1,558 | 1,136 | 883 | |||
Oil and gas | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 5,802 | 4,756 | 2,158 | |||
Oil and gas | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | 21 | 138 | 149 | |||
Oil and gas | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenues | (19) | (130) | (145) | |||
Oil | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 989 | 420 | 95 | |||
Oil | Oil and gas, excluding purchased | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 6,700 | 4,585 | 3,106 | |||
Oil | Oil and gas, excluding purchased | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 3,145 | 1,806 | 1,102 | |||
Oil | Oil and gas, excluding purchased | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 1,232 | 929 | 795 | |||
Oil | Oil and gas, excluding purchased | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 2,323 | 1,850 | 1,209 | |||
Oil | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Oil | Oil and gas, excluding purchased | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Natural Gas | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 117 | 47 | 14 | |||
Natural Gas | Oil and gas, excluding purchased | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 1,545 | 1,207 | 598 | |||
Natural Gas | Oil and gas, excluding purchased | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 370 | 270 | 280 | |||
Natural Gas | Oil and gas, excluding purchased | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 281 | 183 | 67 | |||
Natural Gas | Oil and gas, excluding purchased | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 894 | 754 | 251 | |||
Natural Gas | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Natural Gas | Oil and gas, excluding purchased | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Natural Gas Liquids | ||||||
Other Income (Expense): | ||||||
Revenue from non-customers | 2 | 2 | 0 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 783 | 706 | 333 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | Egypt | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 6 | 9 | 8 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | North Sea | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 45 | 24 | 21 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | U.S. | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 735 | 676 | 304 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | 0 | 0 | 0 | |||
Natural Gas Liquids | Oil and gas, excluding purchased | Intersegment Eliminations & Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Oil, natural gas, and natural gas liquids production revenues | $ (3) | $ (3) | $ 0 | |||
[1] (1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures for further detail. (1) For revenues and gathering, processing, and transmission costs associated with Kinetik, refer to Note 7—Equity Method Interest for further detail. |
SUPPLEMENTAL OIL AND GAS DISC_3
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - Oil and Gas, Exploration and Production - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil and gas production revenues | $ 9,031 | $ 6,501 | $ 4,037 |
Depreciation, depletion, and amortization | 1,130 | 1,255 | 1,643 |
Asset retirement obligation accretion | 116 | 109 | 105 |
Lease operating expenses | 1,436 | 1,243 | 1,129 |
Gathering, processing, and transmission | 369 | 360 | 379 |
Exploration expenses | 146 | 127 | 274 |
Impairments related to oil and gas properties | 4,319 | ||
Production taxes | 252 | 188 | 106 |
Income tax | 2,083 | 996 | (823) |
Operating costs | 5,532 | 4,278 | 7,132 |
Results of operations | 3,499 | 2,223 | (3,095) |
United States | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil and gas production revenues | 3,952 | 3,280 | 1,764 |
Depreciation, depletion, and amortization | 508 | 511 | 726 |
Asset retirement obligation accretion | 34 | 30 | 32 |
Lease operating expenses | 506 | 391 | 400 |
Gathering, processing, and transmission | 304 | 309 | 291 |
Exploration expenses | 24 | 28 | 168 |
Impairments related to oil and gas properties | 3,938 | ||
Production taxes | 252 | 188 | 106 |
Income tax | 488 | 383 | (818) |
Operating costs | 2,116 | 1,840 | 4,843 |
Results of operations | 1,836 | 1,440 | (3,079) |
Egypt | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil and gas production revenues | 3,521 | 2,085 | 1,390 |
Depreciation, depletion, and amortization | 390 | 477 | 540 |
Asset retirement obligation accretion | 0 | 0 | 0 |
Lease operating expenses | 526 | 469 | 424 |
Gathering, processing, and transmission | 22 | 12 | 38 |
Exploration expenses | 84 | 63 | 63 |
Impairments related to oil and gas properties | 374 | ||
Production taxes | 0 | 0 | 0 |
Income tax | 1,100 | 479 | (22) |
Operating costs | 2,122 | 1,500 | 1,417 |
Results of operations | 1,399 | 585 | (27) |
North Sea | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil and gas production revenues | 1,558 | 1,136 | 883 |
Depreciation, depletion, and amortization | 232 | 267 | 377 |
Asset retirement obligation accretion | 82 | 79 | 73 |
Lease operating expenses | 404 | 383 | 305 |
Gathering, processing, and transmission | 43 | 39 | 50 |
Exploration expenses | 35 | 34 | 28 |
Impairments related to oil and gas properties | 7 | ||
Production taxes | 0 | 0 | 0 |
Income tax | 495 | 134 | 17 |
Operating costs | 1,291 | 936 | 857 |
Results of operations | 267 | 200 | 26 |
Other International | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Oil and gas production revenues | 0 | 0 | 0 |
Depreciation, depletion, and amortization | 0 | 0 | 0 |
Asset retirement obligation accretion | 0 | 0 | 0 |
Lease operating expenses | 0 | 0 | 0 |
Gathering, processing, and transmission | 0 | 0 | 0 |
Exploration expenses | 3 | 2 | 15 |
Impairments related to oil and gas properties | 0 | ||
Production taxes | 0 | 0 | 0 |
Income tax | 0 | 0 | 0 |
Operating costs | 3 | 2 | 15 |
Results of operations | $ (3) | $ (2) | $ (15) |
SUPPLEMENTAL OIL AND GAS DISC_4
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved | $ 22 | $ (157) | $ 7 |
Unproved | 28 | 29 | 4 |
Exploration | 237 | 161 | 328 |
Development | 1,286 | 1,085 | 872 |
Costs incurred | 1,573 | 1,118 | 1,211 |
Capitalized interest | 1 | 0 | 3 |
Asset retirement costs | (139) | 149 | 38 |
Egypt PSC modernization impacts - Proved and Unproved | (145) | ||
PSC modernization impacts, incremental value | 247 | ||
PSC modernization impacts, signature bonus | 100 | ||
PSC modernization impacts, other post closing adjustments | 2 | ||
Oil and gas proved property | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
PSC modernization impacts, reduction in proved properties | 165 | ||
Oil and Gas Properties, Unproved | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
PSC modernization impacts, increase in unproved properties | 20 | ||
United States | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved | 19 | 0 | 0 |
Unproved | 28 | 9 | 4 |
Exploration | 4 | 6 | 8 |
Development | 775 | 545 | 332 |
Costs incurred | 826 | 560 | 344 |
Capitalized interest | 0 | 0 | 0 |
Asset retirement costs | 76 | 130 | 9 |
Egypt PSC modernization impacts - Proved and Unproved | 0 | ||
Egypt | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved | 3 | (157) | 7 |
Unproved | 0 | 20 | 0 |
Exploration | 169 | 86 | 102 |
Development | 568 | 404 | 378 |
Costs incurred | 740 | 353 | 487 |
Capitalized interest | 0 | 0 | 0 |
Asset retirement costs | 0 | 0 | 0 |
Egypt PSC modernization impacts - Proved and Unproved | (145) | ||
North Sea | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved | 0 | 0 | 0 |
Unproved | 0 | 0 | 0 |
Exploration | 61 | 39 | 68 |
Development | (57) | 135 | 162 |
Costs incurred | 4 | 174 | 230 |
Capitalized interest | 1 | 0 | 0 |
Asset retirement costs | (215) | 19 | 29 |
Egypt PSC modernization impacts - Proved and Unproved | 0 | ||
Other International | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved | 0 | 0 | 0 |
Unproved | 0 | 0 | 0 |
Exploration | 3 | 30 | 150 |
Development | 0 | 1 | 0 |
Costs incurred | 3 | 31 | 150 |
Capitalized interest | 0 | 0 | 3 |
Asset retirement costs | $ 0 | 0 | $ 0 |
Egypt PSC modernization impacts - Proved and Unproved | $ 0 |
SUPPLEMENTAL OIL AND GAS DISC_5
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Reserve Quantities [Line Items] | ||
Proved properties | $ 40,949 | $ 40,059 |
Unproved properties | 296 | 415 |
Capitalized costs, gross | 41,245 | 40,474 |
Accumulated DD&A | (33,576) | (32,926) |
Capitalized costs, net | 7,669 | 7,548 |
United States | ||
Reserve Quantities [Line Items] | ||
Proved properties | 18,990 | 18,732 |
Unproved properties | 208 | 319 |
Capitalized costs, gross | 19,198 | 19,051 |
Accumulated DD&A | (14,846) | (14,814) |
Capitalized costs, net | 4,352 | 4,237 |
Egypt | ||
Reserve Quantities [Line Items] | ||
Proved properties | 13,014 | 12,373 |
Unproved properties | 77 | 63 |
Capitalized costs, gross | 13,091 | 12,436 |
Accumulated DD&A | (11,157) | (10,767) |
Capitalized costs, net | 1,934 | 1,669 |
North Sea | ||
Reserve Quantities [Line Items] | ||
Proved properties | 8,945 | 8,954 |
Unproved properties | 11 | 33 |
Capitalized costs, gross | 8,956 | 8,987 |
Accumulated DD&A | (7,573) | (7,345) |
Capitalized costs, net | 1,383 | 1,642 |
Other International | ||
Reserve Quantities [Line Items] | ||
Proved properties | 0 | 0 |
Unproved properties | 0 | 0 |
Capitalized costs, gross | 0 | 0 |
Accumulated DD&A | 0 | 0 |
Capitalized costs, net | $ 0 | $ 0 |
SUPPLEMENTAL OIL AND GAS DISC_6
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands | 12 Months Ended | |||
Dec. 31, 2022 MBoe MMcf MBbls | Dec. 31, 2021 MBoe MBbls MMcf | Dec. 31, 2020 MBoe MMcf MBbls | Dec. 31, 2019 MBoe MBbls MMcf | |
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 780,319 | 827,772 | 797,843 | 892,816 |
Proved undeveloped reserves | 75,183 | 85,190 | 75,840 | 117,972 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 912,962 | 873,683 | 1,010,788 | |
Extensions, discoveries and other additions | 33,805 | 101,619 | 78,303 | |
Purchases of minerals in-place | 1,020 | 457 | ||
Revisions of previous estimates | 74,894 | 107,038 | (44,910) | |
Production | (141,179) | (141,642) | (160,945) | |
Sales of minerals in-place | (26,000) | (28,193) | (9,553) | |
Ending balance | 855,502 | 912,962 | 873,683 | |
United States | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 509,827 | 551,384 | 532,994 | 594,595 |
Proved undeveloped reserves | 63,115 | 65,288 | 53,408 | 89,458 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 616,672 | 586,402 | 684,053 | |
Extensions, discoveries and other additions | 21,592 | 76,871 | 39,454 | |
Purchases of minerals in-place | 1,020 | 457 | ||
Revisions of previous estimates | 33,588 | 64,847 | (33,854) | |
Production | (73,930) | (83,712) | (93,698) | |
Sales of minerals in-place | (26,000) | (28,193) | (9,553) | |
Ending balance | 572,942 | 616,672 | 586,402 | |
Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 174,633 | 184,563 | 164,870 | 176,470 |
Proved undeveloped reserves | 8,735 | 12,683 | 13,449 | 15,038 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 197,246 | 178,319 | 191,508 | |
Extensions, discoveries and other additions | 9,278 | 21,765 | 31,905 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 29,647 | 39,071 | (502) | |
Production | (52,803) | (41,909) | (44,592) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 183,368 | 197,246 | 178,319 | |
North Sea | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 95,859 | 91,825 | 99,979 | 121,751 |
Proved undeveloped reserves | 3,333 | 7,219 | 8,983 | 13,476 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 99,044 | 108,962 | 135,227 | |
Extensions, discoveries and other additions | 2,935 | 2,983 | 6,944 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 11,659 | 3,120 | (10,554) | |
Production | (14,446) | (16,021) | (22,655) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 99,192 | 99,044 | 108,962 | |
Noncontrolling Interests | Egypt | ||||
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Proved developed reserves (Energy) | MBoe | 99 | 66 | 59 | 64 |
Crude Oil and Condensate | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 359,447 | 364,687 | 389,483 | 483,430 |
Proved undeveloped reserves | 27,651 | 34,928 | 44,017 | 67,596 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 399,615 | 433,500 | 551,026 | |
Extensions, discoveries and other additions | 19,972 | 33,547 | 40,988 | |
Purchases of minerals in-place | 522 | 126 | ||
Revisions of previous estimates | 41,501 | 18,188 | (71,462) | |
Production | (67,087) | (66,364) | (78,331) | |
Sales of minerals in-place | (7,425) | (19,382) | (8,721) | |
Ending balance | 387,098 | 399,615 | 433,500 | |
Crude Oil and Condensate | United States | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 168,817 | 180,968 | 206,936 | 278,145 |
Proved undeveloped reserves | 16,221 | 18,168 | 25,516 | 46,716 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 199,136 | 232,452 | 324,861 | |
Extensions, discoveries and other additions | 9,776 | 17,869 | 17,858 | |
Purchases of minerals in-place | 522 | 126 | ||
Revisions of previous estimates | 7,170 | (4,479) | (69,247) | |
Production | (24,141) | (27,450) | (32,299) | |
Sales of minerals in-place | (7,425) | (19,382) | (8,721) | |
Ending balance | 185,038 | 199,136 | 232,452 | |
Crude Oil and Condensate | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 108,050 | 106,646 | 95,981 | 103,573 |
Proved undeveloped reserves | 8,557 | 11,003 | 11,228 | 10,831 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 117,649 | 107,209 | 114,404 | |
Extensions, discoveries and other additions | 7,580 | 13,390 | 17,855 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 22,433 | 22,727 | 2,541 | |
Production | (31,055) | (25,677) | (27,591) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 116,607 | 117,649 | 107,209 | |
Crude Oil and Condensate | North Sea | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 82,580 | 77,073 | 86,566 | 101,712 |
Proved undeveloped reserves | 2,873 | 5,757 | 7,273 | 10,049 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 82,830 | 93,839 | 111,761 | |
Extensions, discoveries and other additions | 2,616 | 2,288 | 5,275 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 11,898 | (60) | (4,756) | |
Production | (11,891) | (13,237) | (18,441) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 85,453 | 82,830 | 93,839 | |
Crude Oil and Condensate | Noncontrolling Interests | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 62,000 | 39,000 | 36,000 | 38,000 |
Natural Gas Liquids | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 155,229 | 166,677 | 153,368 | 161,778 |
Proved undeveloped reserves | 15,474 | 16,685 | 15,587 | 24,319 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 183,362 | 168,955 | 186,097 | |
Extensions, discoveries and other additions | 5,501 | 21,143 | 11,844 | |
Purchases of minerals in-place | 233 | 191 | ||
Revisions of previous estimates | 10,281 | 22,862 | (412) | |
Production | (22,334) | (24,806) | (28,118) | |
Sales of minerals in-place | (6,340) | (4,983) | (456) | |
Ending balance | 170,703 | 183,362 | 168,955 | |
Natural Gas Liquids | United States | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 152,999 | 164,172 | 150,599 | 158,794 |
Proved undeveloped reserves | 15,398 | 16,380 | 15,141 | 23,569 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 180,552 | 165,740 | 182,363 | |
Extensions, discoveries and other additions | 5,456 | 21,055 | 11,435 | |
Purchases of minerals in-place | 233 | 191 | ||
Revisions of previous estimates | 10,355 | 22,724 | (469) | |
Production | (21,859) | (24,175) | (27,133) | |
Sales of minerals in-place | (6,340) | (4,983) | (456) | |
Ending balance | 168,397 | 180,552 | 165,740 | |
Natural Gas Liquids | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 0 | 446 | 716 | 667 |
Proved undeveloped reserves | 0 | 30 | 126 | 90 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 476 | 842 | 757 | |
Extensions, discoveries and other additions | 0 | 7 | 97 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | (407) | (180) | 264 | |
Production | (69) | (193) | (276) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 0 | 476 | 842 | |
Natural Gas Liquids | North Sea | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 2,230 | 2,059 | 2,053 | 2,317 |
Proved undeveloped reserves | 76 | 275 | 320 | 660 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | 2,334 | 2,373 | 2,977 | |
Extensions, discoveries and other additions | 45 | 81 | 312 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 333 | 318 | (207) | |
Production | (406) | (438) | (709) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | 2,306 | 2,334 | 2,373 | |
Natural Gas Liquids | Noncontrolling Interests | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | 159 | 281 | 252 | |
Natural Gas | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | MMcf | 1,593,860 | 1,778,442 | 1,529,950 | 1,485,649 |
Proved undeveloped reserves | MMcf | 192,348 | 201,464 | 97,417 | 156,348 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | MMcf | 1,979,906 | 1,627,367 | 1,641,997 | |
Extensions, discoveries and other additions | MMcf | 49,991 | 281,577 | 152,823 | |
Purchases of minerals in-place | MMcf | 1,592 | 839 | ||
Revisions of previous estimates | MMcf | 138,675 | 395,924 | 161,776 | |
Production | MMcf | (310,546) | (302,833) | (326,974) | |
Sales of minerals in-place | MMcf | (73,410) | (22,968) | (2,255) | |
Ending balance | MMcf | 1,786,208 | 1,979,906 | 1,627,367 | |
Natural Gas | United States | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | MMcf | 1,128,066 | 1,237,461 | 1,052,756 | 945,938 |
Proved undeveloped reserves | MMcf | 188,976 | 184,441 | 76,504 | 115,040 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | MMcf | 1,421,902 | 1,129,260 | 1,060,978 | |
Extensions, discoveries and other additions | MMcf | 38,157 | 227,684 | 60,965 | |
Purchases of minerals in-place | MMcf | 1,592 | 839 | ||
Revisions of previous estimates | MMcf | 96,381 | 279,610 | 215,166 | |
Production | MMcf | (167,580) | (192,523) | (205,594) | |
Sales of minerals in-place | MMcf | (73,410) | (22,968) | (2,255) | |
Ending balance | MMcf | 1,317,042 | 1,421,902 | 1,129,260 | |
Natural Gas | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | MMcf | 399,502 | 464,826 | 409,035 | 433,382 |
Proved undeveloped reserves | MMcf | 1,068 | 9,899 | 12,572 | 24,704 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | MMcf | 474,725 | 421,607 | 458,086 | |
Extensions, discoveries and other additions | MMcf | 10,191 | 50,209 | 83,718 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | 45,725 | 99,143 | (19,849) | |
Production | (130,071) | (96,234) | (100,348) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | MMcf | 400,570 | 474,725 | 421,607 | |
Natural Gas | North Sea | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | MMcf | 66,292 | 76,155 | 68,159 | 106,329 |
Proved undeveloped reserves | MMcf | 2,304 | 7,124 | 8,341 | 16,604 |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||||
Beginning balance | MMcf | 83,279 | 76,500 | 122,933 | |
Extensions, discoveries and other additions | MMcf | 1,643 | 3,684 | 8,140 | |
Purchases of minerals in-place | 0 | 0 | ||
Revisions of previous estimates | (3,431) | 17,171 | (33,541) | |
Production | (12,895) | (14,076) | (21,032) | |
Sales of minerals in-place | 0 | 0 | 0 | |
Ending balance | MMcf | 68,596 | 83,279 | 76,500 | |
Natural Gas | Noncontrolling Interests | Egypt | ||||
Reserve Quantities [Line Items] | ||||
Proved developed reserves | MMcf | 224,000 | 158,000 | 141,000 | 153,000 |
SUPPLEMENTAL OIL AND GAS DISC_7
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2021 USD ($) MBoe | Dec. 31, 2022 MBoe | Dec. 31, 2021 MBoe | Dec. 31, 2020 MBoe | |
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 34,000 | 102,000 | 78,000,000 | |
Revision of previous estimate | 75,000 | 107,000 | 45,000,000 | |
PSCs, discounted future net cash flows | $ | $ 750 | |||
PSCs, percentage of reserves consolidated | 96% | |||
Percentage of estimated proved developed reserves classified as proved not producing | 11% | |||
Changes in Product Prices | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 5,000 | 85,000 | 70,000,000 | |
Changes in Engineering and Performance | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 70,000 | 22,000 | 27,000,000 | |
Production Sharing Contracts Modernization Impact | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 43,000 | |||
Other Revisions | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 9,000 | 35,000 | ||
Production Sharing Contracts Modernization Impact, Developed Reserves | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 53,000 | |||
Production Sharing Contracts Modernization Impact, Undeveloped Reserves | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 4,000 | |||
Interest Revisions | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | (2,000) | |||
North America | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 22,000 | 77,000 | 39,000,000 | |
Permian Basin | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 9,000 | 59,000 | ||
Sale of mineral in place | 26,000 | 28,000 | ||
Texas Gulf Coast | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 8,000 | 18,000 | ||
Delaware Basin | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 5,000 | |||
Purchase of mineral in place | 1,000 | |||
International Regions | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 12,000 | 25,000 | 39,000,000 | |
Egypt | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 9,000 | 22,000 | 32,000,000 | |
Egypt | Other Revisions | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 57,000 | |||
North Sea | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 3,000 | 3,000 | 7,000,000 | |
United States | Changes in Engineering and Performance | ||||
Reserve Quantities [Line Items] | ||||
Revision of previous estimate | 18,000 | |||
Eastern Shelf and Magnet Withers/Pickett Ridge | ||||
Reserve Quantities [Line Items] | ||||
Sale of mineral in place | 10,000,000 | |||
Southern Midland Basin | ||||
Reserve Quantities [Line Items] | ||||
Addition from extensions, discoveries, and other additions | 26,000,000 |
SUPPLEMENTAL OIL AND GAS DISC_8
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Cash inflows | $ 52,456 | $ 39,021 | $ 22,219 |
Production costs | (15,548) | (12,378) | (10,336) |
Development costs | (5,366) | (5,567) | (4,636) |
Income tax expense | (6,749) | (2,789) | (780) |
Net cash flows | 24,793 | 18,287 | 6,467 |
10 percent discount rate | (8,026) | (5,927) | (1,155) |
Discounted future net cash flows | $ 16,767 | 12,360 | 5,312 |
Estimated future net cash flow before income tax expenses | 10% | ||
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum | $ 16,100 | 14,900 | 7,100 |
United States | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Cash inflows | 29,490 | 22,852 | 12,537 |
Production costs | (10,221) | (8,323) | (6,244) |
Development costs | (1,598) | (1,632) | (1,555) |
Income tax expense | (1,389) | (134) | 0 |
Net cash flows | 16,282 | 12,763 | 4,738 |
10 percent discount rate | (6,422) | (5,294) | (1,829) |
Discounted future net cash flows | 9,860 | 7,469 | 2,909 |
Egypt | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Cash inflows | 12,819 | 9,337 | 5,560 |
Production costs | (2,086) | (1,712) | (1,704) |
Development costs | (1,471) | (1,402) | (633) |
Income tax expense | (2,729) | (1,887) | (1,096) |
Net cash flows | 6,533 | 4,336 | 2,127 |
10 percent discount rate | (1,400) | (983) | (437) |
Discounted future net cash flows | 5,133 | 3,353 | 1,690 |
Egypt | Noncontrolling Interests | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Discounted future net cash flows | 2,500 | 1,600 | 563 |
North Sea | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Cash inflows | 10,147 | 6,832 | 4,122 |
Production costs | (3,241) | (2,343) | (2,388) |
Development costs | (2,297) | (2,533) | (2,448) |
Income tax expense | (2,631) | (768) | 316 |
Net cash flows | 1,978 | 1,188 | (398) |
10 percent discount rate | (204) | 350 | 1,111 |
Discounted future net cash flows | $ 1,774 | $ 1,538 | $ 713 |
SUPPLEMENTAL OIL AND GAS DISC_9
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Extractive Industries [Abstract] | |||
Sales, net of production costs | $ (6,970) | $ (4,707) | $ (2,422) |
Net change in prices and production costs | 8,627 | 9,376 | (5,753) |
Discoveries and improved recovery, net of related costs | 1,132 | 1,749 | 751 |
Change in future development costs | (347) | (839) | 20 |
Previously estimated development costs incurred during the period | 669 | 545 | 576 |
Revision of quantities | 2,621 | 1,983 | (418) |
Purchases of minerals in-place | 17 | 1 | 0 |
Accretion of discount | 1,489 | 626 | 1,236 |
Change in income taxes | (2,371) | (1,583) | 1,533 |
Sales of minerals in-place | (363) | (116) | (104) |
Change in production rates and other | (97) | 13 | 11 |
Change in the discounted future net cash flows, Total | $ 4,407 | $ 7,048 | $ (4,570) |