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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2023or
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☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _________ to _________Commission File Number: 1-40144
APA CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware | 86-1430562 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices) (Zip Code)
(713) 296-6000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
Common Stock, $0.625 par value | | APA | | Nasdaq Global Select Market |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | | ☒ | | Accelerated filer | | ☐ |
Non-accelerated filer | | ☐ | | Smaller reporting company | | ☐ |
| | | | Emerging growth company | | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
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Number of shares of registrant’s common stock outstanding as of October 31, 2023 | 306,719,421 | |
TABLE OF CONTENTS
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Item | | | Page |
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| PART I - FINANCIAL INFORMATION | | |
1. | | | |
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3. | | | |
4. | | | |
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| PART II - OTHER INFORMATION | | |
1. | | | |
1A. | | | |
2. | | | |
5. | | | |
6. | | | |
FORWARD-LOOKING STATEMENTS AND RISKS
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations and capital returns framework, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2022, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:
•changes in local, regional, national, and international economic conditions, including as a result of any epidemics or pandemics, such as the coronavirus disease (COVID-19) pandemic and any related variants;
•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;
•the Company’s commodity hedging arrangements;
•the supply and demand for oil, natural gas, NGLs, and other products or services;
•production and reserve levels;
•drilling risks;
•economic and competitive conditions, including market and macro-economic disruptions resulting from the Russian war in Ukraine, the armed conflict in Israel and Gaza, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);
•the availability of capital resources;
•capital expenditures and other contractual obligations;
•currency exchange rates;
•weather conditions;
•inflation rates;
•the impact of changes in tax legislation;
•the availability of goods and services;
•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
•legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
•the Company’s performance on environmental, social, and governance measures;
•terrorism or cyberattacks;
•the occurrence of property acquisitions or divestitures;
•the integration of acquisitions;
•the Company’s ability to access the capital markets;
•market-related risks, such as general credit, liquidity, and interest-rate risks;
•the benefits derived from the operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022);
•other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022;
•other risks and uncertainties disclosed in the Company’s third-quarter 2023 earnings release;
•other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q; and •other factors disclosed in the other filings that the Company makes with the Securities and Exchange Commission.
Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.
DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:
“3-D” means three-dimensional.
“4-D” means four-dimensional.
“b/d” means barrels of oil or NGLs per day.
“bbl” or “bbls” means barrel or barrels of oil or NGLs.
“bcf” means billion cubic feet of natural gas.
“bcf/d” means one bcf per day.
“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.
“boe/d” means boe per day.
“Btu” means a British thermal unit, a measure of heating value.
“Liquids” means oil and NGLs.
“LNG” means liquefied natural gas.
“Mb/d” means Mbbls per day.
“Mbbls” means thousand barrels of oil or NGLs.
“Mboe” means thousand boe.
“Mboe/d” means Mboe per day.
“Mcf” means thousand cubic feet of natural gas.
“Mcf/d” means Mcf per day.
“MMbbls” means million barrels of oil or NGLs.
“MMboe” means million boe.
“MMBtu” means million Btu.
“MMBtu/d” means MMBtu per day.
“MMcf” means million cubic feet of natural gas.
“MMcf/d” means MMcf per day.
“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.
“NYMEX” means New York Mercantile Exchange.
“oil” includes crude oil and condensate.
“PUD” means proved undeveloped.
“SEC” means the United States Securities and Exchange Commission.
“Tcf” means trillion cubic feet of natural gas.
“U.K.” means United Kingdom.
“U.S.” means United States.
With respect to information relating to the Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.
References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions, except share data) |
REVENUES AND OTHER: | | | | | | | | |
Oil, natural gas, and natural gas liquids production revenues(1) | | $ | 2,079 | | | $ | 2,302 | | | $ | 5,500 | | | $ | 7,147 | |
Purchased oil and gas sales(1) | | 229 | | | 585 | | | 612 | | | 1,456 | |
Total revenues | | 2,308 | | | 2,887 | | | 6,112 | | | 8,603 | |
Derivative instrument gains (losses), net | | — | | | (44) | | | 104 | | | (138) | |
Gain on divestitures, net | | 1 | | | 31 | | | 7 | | | 1,180 | |
| | | | | | | | |
Other, net | | — | | | (2) | | | 77 | | | 107 | |
| | 2,309 | | | 2,872 | | | 6,300 | | | 9,752 | |
OPERATING EXPENSES: | | | | | | | | |
Lease operating expenses | | 394 | | | 364 | | | 1,076 | | | 1,067 | |
Gathering, processing, and transmission(1) | | 89 | | | 99 | | | 245 | | | 274 | |
Purchased oil and gas costs(1) | | 211 | | | 573 | | | 558 | | | 1,452 | |
Taxes other than income | | 61 | | | 82 | | | 163 | | | 230 | |
Exploration | | 49 | | | 95 | | | 144 | | | 193 | |
General and administrative | | 139 | | | 69 | | | 276 | | | 314 | |
Transaction, reorganization, and separation | | 5 | | | 4 | | | 11 | | | 21 | |
Depreciation, depletion, and amortization | | 418 | | | 310 | | | 1,117 | | | 879 | |
Asset retirement obligation accretion | | 29 | | | 29 | | | 86 | | | 87 | |
Impairments | | — | | | — | | | 46 | | | — | |
Financing costs, net | | 81 | | | 75 | | | 235 | | | 303 | |
| | 1,476 | | | 1,700 | | | 3,957 | | | 4,820 | |
NET INCOME BEFORE INCOME TAXES | | 833 | | | 1,172 | | | 2,343 | | | 4,932 | |
Current income tax provision | | 422 | | | 357 | | | 1,022 | | | 1,164 | |
Deferred income tax provision (benefit) | | (144) | | | 285 | | | (22) | | | 225 | |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | | 555 | | | 530 | | | 1,343 | | | 3,543 | |
Net income attributable to noncontrolling interest – Egypt | | 96 | | | 108 | | | 261 | | | 368 | |
Net income attributable to noncontrolling interest – Altus | | — | | | — | | | — | | | 14 | |
Net loss attributable to Altus Preferred Unit limited partners | | — | | | — | | | — | | | (70) | |
NET INCOME ATTRIBUTABLE TO COMMON STOCK | | $ | 459 | | | $ | 422 | | | $ | 1,082 | | | $ | 3,231 | |
| | | | | | | | |
NET INCOME PER COMMON SHARE: | | | | | | | | |
Basic | | $ | 1.49 | | | $ | 1.28 | | | $ | 3.50 | | | $ | 9.54 | |
Diluted | | $ | 1.49 | | | $ | 1.28 | | | $ | 3.50 | | | $ | 9.51 | |
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | | | | | | |
Basic | | 308 | | | 329 | | | 309 | | | 339 | |
Diluted | | 308 | | | 330 | | | 309 | | | 340 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
1
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | | $ | 555 | | | $ | 530 | | | $ | 1,343 | | | $ | 3,543 | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | | | | | | | | |
| | | | | | | | |
Pension and postretirement benefit plan | | — | | | — | | | 3 | | | (1) | |
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS | | 555 | | | 530 | | | 1,346 | | | 3,542 | |
Comprehensive income attributable to noncontrolling interest – Egypt | | 96 | | | 108 | | | 261 | | | 368 | |
Comprehensive income attributable to noncontrolling interest – Altus | | — | | | — | | | — | | | 14 | |
Comprehensive loss attributable to Altus Preferred Unit limited partners | | — | | | — | | | — | | | (70) | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK | | $ | 459 | | | $ | 422 | | | $ | 1,085 | | | $ | 3,230 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
2
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2023 | | 2022 |
| | | | |
| | (In millions) |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
Net income including noncontrolling interests | | $ | 1,343 | | | $ | 3,543 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
Unrealized derivative instrument (gains) losses, net | | (61) | | | 119 | |
Gain on divestitures, net | | (7) | | | (1,180) | |
Exploratory dry hole expense and unproved leasehold impairments | | 91 | | | 129 | |
Depreciation, depletion, and amortization | | 1,117 | | | 879 | |
Asset retirement obligation accretion | | 86 | | | 87 | |
Impairments | | 46 | | | — | |
Provision for (benefit from) deferred income taxes | | (22) | | | 225 | |
(Gain) loss on extinguishment of debt | | (9) | | | 67 | |
| | | | |
Other, net | | (45) | | | (91) | |
Changes in operating assets and liabilities: | | | | |
Receivables | | (289) | | | (554) | |
Inventories | | 19 | | | (81) | |
Drilling advances and other current assets | | 40 | | | 7 | |
Deferred charges and other long-term assets | | 227 | | | (3) | |
Accounts payable | | (2) | | | 175 | |
Accrued expenses | | 1 | | | 249 | |
Deferred credits and noncurrent liabilities | | (436) | | | (41) | |
NET CASH PROVIDED BY OPERATING ACTIVITIES | | 2,099 | | | 3,530 | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | |
Additions to upstream oil and gas property | | (1,747) | | | (1,168) | |
Acquisition of Delaware Basin properties | | (24) | | | (563) | |
Leasehold and property acquisitions | | (11) | | | (30) | |
Proceeds from sale of oil and gas properties | | 29 | | | 778 | |
Proceeds from sale of Kinetik shares | | — | | | 224 | |
Deconsolidation of Altus cash and cash equivalents | | — | | | (143) | |
Other, net | | (29) | | | 8 | |
NET CASH USED IN INVESTING ACTIVITIES | | (1,782) | | | (894) | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | |
Proceeds from (payments on) revolving credit facilities, net | | 202 | | | (22) | |
| | | | |
| | | | |
Payments on Apache fixed-rate debt | | (65) | | | (1,370) | |
Distributions to noncontrolling interest – Egypt | | (154) | | | (237) | |
Treasury stock activity, net | | (208) | | | (884) | |
Dividends paid to APA common stockholders | | (232) | | | (127) | |
Other, net | | (10) | | | (30) | |
NET CASH USED IN FINANCING ACTIVITIES | | (467) | | | (2,670) | |
| | | | |
NET DECREASE IN CASH AND CASH EQUIVALENTS | | (150) | | | (34) | |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | | 245 | | | 302 | |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 95 | | | $ | 268 | |
| | | | |
SUPPLEMENTARY CASH FLOW DATA: | | | | |
Interest paid, net of capitalized interest | | $ | 278 | | | $ | 274 | |
Income taxes paid, net of refunds | | 867 | | | 1,029 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
3
APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
| | | | | | | | | | | | | | |
| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions, except share data) |
ASSETS | | | | |
CURRENT ASSETS: | | | | |
Cash and cash equivalents | | $ | 95 | | | $ | 245 | |
Receivables, net of allowance of $103 and $117 | | 1,753 | | | 1,466 | |
| | 952 | | | 997 | |
| | 2,800 | | | 2,708 | |
PROPERTY AND EQUIPMENT: | | | | |
Oil and gas properties | | 43,908 | | | 42,356 | |
Gathering, processing, and transmission facilities | | 447 | | | 449 | |
Other | | 613 | | | 613 | |
Less: Accumulated depreciation, depletion, and amortization | | (35,468) | | | (34,406) | |
| | 9,500 | | | 9,012 | |
OTHER ASSETS: | | | | |
Equity method interests (Note 6) | | 681 | | | 624 | |
Decommissioning security for sold Gulf of Mexico properties (Note 11) | | 38 | | | 217 | |
Deferred charges and other | | 526 | | | 586 | |
| | $ | 13,545 | | | $ | 13,147 | |
| | | | |
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY | | | | |
CURRENT LIABILITIES: | | | | |
Accounts payable | | $ | 741 | | | $ | 771 | |
Current debt | | 2 | | | 2 | |
Other current liabilities (Note 7) | | 1,892 | | | 2,143 | |
| | 2,635 | | | 2,916 | |
| | 5,582 | | | 5,451 | |
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: | | | | |
Income taxes | | 305 | | | 314 | |
Asset retirement obligation (Note 8) | | 2,006 | | | 1,940 | |
Decommissioning contingency for sold Gulf of Mexico properties (Note 11) | | 470 | | | 738 | |
Other | | 440 | | | 443 | |
| | 3,221 | | | 3,435 | |
| | | | |
EQUITY: | | | | |
Common stock, $0.625 par, 860,000,000 shares authorized, 420,593,611 and 419,869,987 shares issued, respectively | | 263 | | | 262 | |
Paid-in capital | | 11,197 | | | 11,420 | |
Accumulated deficit | | (4,732) | | | (5,814) | |
Treasury stock, at cost, 113,797,342 and 108,310,838 shares, respectively | | (5,667) | | | (5,459) | |
Accumulated other comprehensive income | | 17 | | | 14 | |
APA SHAREHOLDERS’ EQUITY | | 1,078 | | | 423 | |
Noncontrolling interest – Egypt | | 1,029 | | | 922 | |
| | | | |
TOTAL EQUITY | | 2,107 | | | 1,345 | |
| | $ | 13,545 | | | $ | 13,147 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
4
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1) | | | Common Stock | | Paid-In Capital | | Accumulated Deficit | | Treasury Stock | | Accumulated Other Comprehensive Income | | APA SHAREHOLDERS’ EQUITY | | Noncontrolling Interests(1) | | TOTAL EQUITY |
| | | | | | | | | | | | | | | | | | | |
| | (In millions) |
For the Quarter Ended September 30, 2022 | | | | | | | | | | | | | | | | | | | |
Balance at June 30, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,567 | | | $ | (6,679) | | | $ | (4,587) | | | $ | 21 | | | $ | 584 | | | $ | 921 | | | $ | 1,505 | |
Net income attributable to common stock | | — | | | | — | | | — | | | 422 | | | — | | | — | | | 422 | | | — | | | 422 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 108 | | | 108 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (78) | | | (78) | |
Common dividends declared ($0.25 per share) | | — | | | | — | | | (80) | | | — | | | — | | | — | | | (80) | | | — | | | (80) | |
| | | | | | | | | | | | | | | | | | | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (333) | | | — | | | (333) | | | — | | | (333) | |
Other | | — | | | | — | | | 7 | | | — | | | — | | | — | | | 7 | | | — | | | 7 | |
Balance at September 30, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,494 | | | $ | (6,257) | | | $ | (4,920) | | | $ | 21 | | | $ | 600 | | | $ | 951 | | | $ | 1,551 | |
| | | | | | | | | | | | | | | | | | | |
For the Quarter Ended September 30, 2023 | | | | | | | | | | | | | | | | | | | |
Balance at June 30, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,267 | | | $ | (5,191) | | | $ | (5,647) | | | $ | 17 | | | $ | 709 | | | $ | 987 | | | $ | 1,696 | |
Net income attributable to common stock | | — | | | | — | | | — | | | 459 | | | — | | | — | | | 459 | | | — | | | 459 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 96 | | | 96 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (54) | | | (54) | |
Common dividends declared ($0.25 per share) | | — | | | | — | | | (77) | | | — | | | — | | | — | | | (77) | | | — | | | (77) | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (20) | | | — | | | (20) | | | — | | | (20) | |
| | | | | | | | | | | | | | | | | | | |
Other | | — | | | | — | | | 7 | | | — | | | — | | | — | | | 7 | | | — | | | 7 | |
Balance at September 30, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,197 | | | $ | (4,732) | | | $ | (5,667) | | | $ | 17 | | | $ | 1,078 | | | $ | 1,029 | | | $ | 2,107 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
5
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS - Continued
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1) | | | Common Stock | | Paid-In Capital | | Accumulated Deficit | | Treasury Stock | | Accumulated Other Comprehensive Income | | APA SHAREHOLDERS’ EQUITY (DEFICIT) | | Noncontrolling Interests(1) | | TOTAL EQUITY (DEFICIT) |
| | | | | | | | | | | | | | | | | | | |
| | (In millions) |
For the Nine Months Ended September 30, 2022 | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2021 | | $ | 712 | | | | $ | 262 | | | $ | 11,645 | | | $ | (9,488) | | | $ | (4,036) | | | $ | 22 | | | $ | (1,595) | | | $ | 878 | | | $ | (717) | |
Net income attributable to common stock | | — | | | | | | | | 3,231 | | | — | | | — | | | 3,231 | | | — | | | 3,231 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 368 | | | 368 | |
Net income attributable to noncontrolling interest – Altus | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 14 | | | 14 | |
Net loss attributable to Altus Preferred Unit limited partners | | (70) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (237) | | | (237) | |
Common dividends declared ($0.50 per share) | | — | | | | — | | | (165) | | | — | | | — | | | — | | | (165) | | | — | | | (165) | |
Deconsolidation of Altus | | (642) | | | | — | | | — | | | — | | | — | | | — | | | — | | | (72) | | | (72) | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (884) | | | — | | | (884) | | | — | | | (884) | |
Other | | — | | | | — | | | 14 | | | — | | | — | | | (1) | | | 13 | | | — | | | 13 | |
Balance at September 30, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,494 | | | $ | (6,257) | | | $ | (4,920) | | | $ | 21 | | | $ | 600 | | | $ | 951 | | | $ | 1,551 | |
| | | | | | | | | | | | | | | | | | | |
For the Nine Months Ended September 30, 2023 | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,420 | | | $ | (5,814) | | | $ | (5,459) | | | $ | 14 | | | $ | 423 | | | $ | 922 | | | $ | 1,345 | |
Net income attributable to common stock | | — | | | | — | | | — | | | 1,082 | | | — | | | — | | | 1,082 | | | — | | | 1,082 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 261 | | | 261 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (154) | | | (154) | |
Common dividends declared ($0.75 per share) | | — | | | | — | | | (232) | | | — | | | — | | | — | | | (232) | | | — | | | (232) | |
| | | | | | | | | | | | | | | | | | | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (208) | | | — | | | (208) | | | — | | | (208) | |
Other | | — | | | | 1 | | | 9 | | | — | | | — | | | 3 | | | 13 | | | — | | | 13 | |
Balance at September 30, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,197 | | | $ | (4,732) | | | $ | (5,667) | | | $ | 17 | | | $ | 1,078 | | | $ | 1,029 | | | $ | 2,107 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
6
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, which contains a summary of the Company’s significant accounting policies and other disclosures.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2023, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary.
On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.
The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail. Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom. Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
During the three and nine months ended September 30, 2023 and 2022, the Company recorded no asset impairments in connection with fair value assessments.
Revenue Recognition
There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022.
Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC.
Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
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.
2. ACQUISITIONS AND DIVESTITURES
2023 Activity
During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $1 million and $11 million, respectively.
During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions.
2022 Activity
During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations.
During the third quarter and first nine months of 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $3 million and $30 million, respectively.
During the third quarter and first nine months of 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $37 million and $52 million, respectively, recognizing a gain of approximately $34 million and $36 million, respectively, upon closing of these transactions.
During the first nine months of 2022, the Company completed a transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million.
The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed.
As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s share of ALTM’s deconsolidated balance sheet of $193 million and the fair value of $802 million of its approximate 20 percent retained ownership in the combined entity.
During the first quarter of 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and recognized a loss of $25 million, including transaction fees. Refer to Note 6—Equity Method Interests for further detail. 3. CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $541 million and $474 million as of September 30, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity offshore Suriname and in Egypt. Approximately $5 million of suspended well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the third quarter of 2023.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.
4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023, the Company had derivative positions with seven counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.
Derivative Instruments
Commodity Derivative Instruments
As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Basis Swap Purchased | | Basis Swap Sold |
Production Period | | Settlement Index | | MMBtu (in 000’s) | | Weighted Average Price Differential | | MMBtu (in 000’s) | | Weighted Average Price Differential |
October—December 2023 | | NYMEX Henry Hub/IF Waha | | 18,400 | | | $(1.15) | | — | | | — |
October—December 2023 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 18,400 | | | $(0.08) |
January—June 2024 | | NYMEX Henry Hub/IF Waha | | 16,380 | | | $(1.15) | | — | | | — |
January—June 2024 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 16,380 | | | $(0.10) |
Fair Value Measurements
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
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| | Fair Value Measurements Using | | | | | | |
| | Quoted Price in Active Markets (Level 1) | | Significant Other Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value | | Netting(1) | | Carrying Amount |
| | | | | | | | | | | | |
| | (In millions) |
September 30, 2023 | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | |
Commodity derivative instruments | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | |
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December 31, 2022 | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | |
Commodity derivative instruments | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | |
Liabilities: | | | | | | | | | | | | |
Commodity derivative instruments | | — | | | 50 | | | — | | | 50 | | | — | | | 50 | |
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(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.
The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.
Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
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| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Current Assets: Other current assets | | $ | 16 | | | $ | — | |
Other Assets: Deferred charges and other | | — | | | 5 | |
Total derivative assets | | $ | 16 | | | $ | 5 | |
| | | | |
Current Liabilities: Other current liabilities | | $ | — | | | $ | 50 | |
| | | | |
Total derivative liabilities | | $ | — | | | $ | 50 | |
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
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| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Realized: | | | | | | | | |
Commodity derivative instruments | | $ | 19 | | | $ | (2) | | | $ | 43 | | | $ | (11) | |
Foreign currency derivative instruments | | — | | | (6) | | | — | | | (8) | |
Realized gains (losses), net | | 19 | | | (8) | | | 43 | | | (19) | |
Unrealized: | | | | | | | | |
Commodity derivative instruments | | (19) | | | (35) | | | 61 | | | (79) | |
| | | | | | | | |
Foreign currency derivative instruments | | — | | | (1) | | | — | | | (9) | |
Preferred Units embedded derivative | | — | | | — | | | — | | | (31) | |
Unrealized gains (losses), net | | (19) | | | (36) | | | 61 | | | (119) | |
Derivative instrument gains (losses), net | | $ | — | | | $ | (44) | | | $ | 104 | | | $ | (138) | |
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
5. OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets:
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| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Inventories | | $ | 443 | | | $ | 427 | |
Drilling advances | | 87 | | | 89 | |
| | | | |
Prepaid assets and other | | 49 | | | 31 | |
Current decommissioning security for sold Gulf of Mexico assets | | 373 | | | 450 | |
Total Other current assets | | $ | 952 | | | $ | 997 | |
6. EQUITY METHOD INTERESTS
The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.
The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares. The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock.
The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49 million in the first nine months of 2023 and 2022, respectively. These gains and losses were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.
The following table represents sales and costs associated with Kinetik:
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| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Natural gas and NGLs sales | | $ | 35 | | | $ | — | | | $ | 78 | | | $ | — | |
Purchased oil and gas sales | | 11 | | | — | | | 18 | | | — | |
| | $ | 46 | | | $ | — | | | $ | 96 | | | $ | — | |
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Gathering, processing, and transmission costs | | $ | 26 | | | $ | 28 | | | $ | 81 | | | $ | 64 | |
Purchased oil and gas costs | | 37 | | | — | | | 65 | | | — | |
| | $ | 63 | | | $ | 28 | | | $ | 146 | | | $ | 64 | |
As of September 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $43 million and receivables from Kinetik of approximately $29 million.
7. OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities:
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| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Accrued operating expenses | | $ | 161 | | | $ | 145 | |
Accrued exploration and development | | 328 | | | 333 | |
Accrued compensation and benefits | | 379 | | | 514 | |
Accrued interest | | 66 | | | 97 | |
Accrued income taxes | | 228 | | | 90 | |
Current asset retirement obligation | | 55 | | | 55 | |
Current operating lease liability | | 108 | | | 167 | |
| | | | |
Current decommissioning contingency for sold Gulf of Mexico properties | | 225 | | | 450 | |
Other | | 342 | | | 292 | |
Total Other current liabilities | | $ | 1,892 | | | $ | 2,143 | |
8. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
| | | | | | | | |
| | September 30, 2023 |
| | (In millions) |
Asset retirement obligation, December 31, 2022 | | $ | 1,995 | |
Liabilities incurred | | 14 | |
| | |
Liabilities settled | | (34) | |
| | |
| | |
| | |
Accretion expense | | 86 | |
| | |
Asset retirement obligation, September 30, 2023 | | 2,061 | |
Less current portion | | (55) | |
Asset retirement obligation, long-term | | $ | 2,006 | |
9. DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
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| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Apache notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 4,835 | | | $ | 4,908 | |
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Syndicated credit facilities(2) | | 768 | | | 566 | |
Apache finance lease obligations | | 33 | | | 34 | |
Unamortized discount | | (26) | | | (27) | |
Debt issuance costs | | (26) | | | (28) | |
Total debt | | 5,584 | | | 5,453 | |
Current maturities | | (2) | | | (2) | |
Long-term debt | | $ | 5,582 | | | $ | 5,451 | |
(1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively.
The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.
At each of September 30, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations.
During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).
•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.
Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023, there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Interest expense | | $ | 89 | | | $ | 80 | | | $ | 266 | | | $ | 249 | |
Amortization of debt issuance costs | | 1 | | | 1 | | | 3 | | | 8 | |
Capitalized interest | | (7) | | | (5) | | | (18) | | | (13) | |
(Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | |
Interest income | | (2) | | | (1) | | | (7) | | | (8) | |
Financing costs, net | | $ | 81 | | | $ | 75 | | | $ | 235 | | | $ | 303 | |
10. INCOME TAXES
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
During the third quarter of 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023.
The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
11. COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2023, the Company has an accrued liability of approximately $49 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
Argentine Environmental Claims
On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration
As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.
Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.
Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized by the end of 2023.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit.
Kulp Minerals Lawsuit
On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company intends to vigorously defend this lawsuit.
On January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, on February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits.
Environmental Matters
As of September 30, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings.
On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings.
The Company is not aware of any environmental claims existing as of September 30, 2023, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.
By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
As of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.”
On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Apache intends to vigorously defend these claims, and will vigorously pursue its counterclaims.
12. CAPITAL STOCK
Net Income per Common Share
The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, |
| | 2023 | | 2022 |
| | Income | | Shares | | Per Share | | Income | | Shares | | Per Share |
| | | | | | | | | | | | |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 329 | | | $ | 1.28 | |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | — | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 330 | | | $ | 1.28 | |
| | For the Nine Months Ended September 30, |
| | 2023 | | 2022 |
| | Income | | Shares | | Per Share | | Income | | Shares | | Per Share |
| | | | | | | | | | | | |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 339 | | | $ | 9.54 | |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | (0.03) | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 340 | | | $ | 9.51 | |
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.7 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.5 million during the first nine months of 2023 and 2022, respectively.
Stock Repurchase Program
During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock.
In the third quarter of 2023, the Company repurchased approximately 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share, and as of September 30, 2023, the Company had remaining authorization to repurchase up to 47.1 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share.
The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares.
The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions.
Common Stock Dividend
For the quarters ended September 30, 2023 and 2022, the Company paid $77 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127 million, respectively, in dividends on its common stock.
During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.
13. BUSINESS SEGMENT INFORMATION
As of September 30, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Quarter Ended September 30, 2023 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 724 | | | $ | 348 | | | $ | 633 | | | $ | — | | | $ | — | | | $ | 1,705 | |
Natural gas revenues | | 81 | | | 66 | | | 89 | | | — | | | — | | | 236 | |
Natural gas liquids revenues | | — | | | 5 | | | 133 | | | — | | | — | | | 138 | |
Oil, natural gas, and natural gas liquids production revenues | | 805 | | | 419 | | | 855 | | | — | | | — | | | 2,079 | |
Purchased oil and gas sales | | — | | | — | | | 229 | | | — | | | — | | | 229 | |
| | | | | | | | | | | | |
| | 805 | | | 419 | | | 1,084 | | | — | | | — | | | 2,308 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 128 | | | 102 | | | 164 | | | — | | | — | | | 394 | |
Gathering, processing, and transmission | | 13 | | | 15 | | | 61 | | | — | | | — | | | 89 | |
Purchased oil and gas costs | | — | | | — | | | 211 | | | — | | | — | | | 211 | |
Taxes other than income | | — | | | — | | | 61 | | | — | | | — | | | 61 | |
Exploration | | 25 | | | 9 | | | 4 | | | — | | | 11 | | | 49 | |
Depreciation, depletion, and amortization | | 129 | | | 90 | | | 199 | | | — | | | — | | | 418 | |
Asset retirement obligation accretion | | — | | | 20 | | | 9 | | | — | | | — | | | 29 | |
| | | | | | | | | | | | |
| | 295 | | | 236 | | | 709 | | | — | | | 11 | | | 1,251 | |
Operating Income (Loss)(2) | | $ | 510 | | | $ | 183 | | | $ | 375 | | | $ | — | | | $ | (11) | | | 1,057 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 1 | |
| | | | | | | | | | | | |
General and administrative | | | | | | | | | | | | (139) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (5) | |
Financing costs, net | | | | | | | | | | | | (81) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 833 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Nine Months Ended September 30, 2023 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 1,971 | | | $ | 865 | | | $ | 1,631 | | | $ | — | | | $ | — | | | $ | 4,467 | |
Natural gas revenues | | 264 | | | 165 | | | 229 | | | — | | | — | | | 658 | |
Natural gas liquids revenues | | — | | | 19 | | | 356 | | | — | | | — | | | 375 | |
Oil, natural gas, and natural gas liquids production revenues | | 2,235 | | | 1,049 | | | 2,216 | | | — | | | — | | | 5,500 | |
Purchased oil and gas sales | | — | | | — | | | 612 | | | — | | | — | | | 612 | |
| | | | | | | | | | | | |
| | 2,235 | | | 1,049 | | | 2,828 | | | — | | | — | | | 6,112 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 346 | | | 278 | | | 452 | | | — | | | — | | | 1,076 | |
Gathering, processing, and transmission | | 26 | | | 38 | | | 181 | | | — | | | — | | | 245 | |
Purchased oil and gas costs | | — | | | — | | | 558 | | | — | | | — | | | 558 | |
Taxes other than income | | — | | | — | | | 163 | | | — | | | — | | | 163 | |
Exploration | | 91 | | | 18 | | | 10 | | | — | | | 25 | | | 144 | |
Depreciation, depletion, and amortization | | 378 | | | 209 | | | 530 | | | — | | | — | | | 1,117 | |
Asset retirement obligation accretion | | — | | | 57 | | | 29 | | | — | | | — | | | 86 | |
Impairments | | — | | | 46 | | | — | | | — | | | — | | | 46 | |
| | 841 | | | 646 | | | 1,923 | | | — | | | 25 | | | 3,435 | |
Operating Income (Loss)(2) | | $ | 1,394 | | | $ | 403 | | | $ | 905 | | | $ | — | | | $ | (25) | | | 2,677 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
Derivative instrument gains, net | | | | | | | | | | | | 104 | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 7 | |
Other, net | | | | | | | | | | | | 77 | |
General and administrative | | | | | | | | | | | | (276) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (11) | |
Financing costs, net | | | | | | | | | | | | (235) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 2,343 | |
| | | | | | | | | | | | |
Total Assets(3) | | $ | 3,518 | | | $ | 1,665 | | | $ | 7,827 | | | $ | — | | | $ | 535 | | | $ | 13,545 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Quarter Ended September 30, 2022 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 739 | | | $ | 303 | | | $ | 630 | | | $ | — | | | $ | — | | | $ | 1,672 | |
Natural gas revenues | | 84 | | | 44 | | | 300 | | | — | | | — | | | 428 | |
Natural gas liquids revenues | | — | | | 5 | | | 197 | | | — | | | — | | | 202 | |
Oil, natural gas, and natural gas liquids production revenues | | 823 | | | 352 | | | 1,127 | | | — | | | — | | | 2,302 | |
Purchased oil and gas sales | | — | | | — | | | 585 | | | — | | | — | | | 585 | |
| | | | | | | | | | | | |
| | 823 | | | 352 | | | 1,712 | | | — | | | — | | | 2,887 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 119 | | | 107 | | | 138 | | | — | | | — | | | 364 | |
Gathering, processing, and transmission | | 5 | | | 7 | | | 87 | | | — | | | — | | | 99 | |
Purchased oil and gas costs | | — | | | — | | | 573 | | | — | | | — | | | 573 | |
Taxes other than income | | — | | | — | | | 82 | | | — | | | — | | | 82 | |
Exploration | | 29 | | | 1 | | | 16 | | | — | | | 49 | | | 95 | |
Depreciation, depletion, and amortization | | 97 | | | 52 | | | 161 | | | — | | | — | | | 310 | |
Asset retirement obligation accretion | | — | | | 21 | | | 8 | | | — | | | — | | | 29 | |
| | | | | | | | | | | | |
| | 250 | | | 188 | | | 1,065 | | | — | | | 49 | | | 1,552 | |
Operating Income (Loss)(2) | | $ | 573 | | | $ | 164 | | | $ | 647 | | | $ | — | | | $ | (49) | | | 1,335 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
| | | | | | | | | | | | |
Derivative instrument losses, net | | | | | | | | | | | | (44) | |
Gain on divestitures, net | | | | | | | | | | | | 31 | |
Other, net | | | | | | | | | | | | (2) | |
General and administrative | | | | | | | | | | | | (69) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (4) | |
Financing costs, net | | | | | | | | | | | | (75) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 1,172 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Nine Months Ended September 30, 2022 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 2,431 | | | $ | 938 | | | $ | 1,883 | | | $ | — | | | $ | — | | | $ | 5,252 | |
Natural gas revenues | | 270 | | | 207 | | | 764 | | | — | | | — | | | 1,241 | |
Natural gas liquids revenues | | 6 | | | 33 | | | 618 | | | — | | | (3) | | | 654 | |
Oil, natural gas, and natural gas liquids production revenues | | 2,707 | | | 1,178 | | | 3,265 | | | — | | | (3) | | | 7,147 | |
Purchased oil and gas sales | | — | | | — | | | 1,451 | | | 5 | | | — | | | 1,456 | |
Midstream service affiliate revenues | | — | | | — | | | — | | | 16 | | | (16) | | | — | |
| | 2,707 | | | 1,178 | | | 4,716 | | | 21 | | | (19) | | | 8,603 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 381 | | | 321 | | | 366 | | | — | | | (1) | | | 1,067 | |
Gathering, processing, and transmission | | 15 | | | 31 | | | 241 | | | 5 | | | (18) | | | 274 | |
Purchased oil and gas costs | | — | | | — | | | 1,452 | | | — | | | — | | | 1,452 | |
Taxes other than income | | — | | | — | | | 227 | | | 3 | | | — | | | 230 | |
Exploration | | 56 | | | 8 | | | 21 | | | — | | | 108 | | | 193 | |
Depreciation, depletion, and amortization | | 285 | | | 168 | | | 424 | | | 2 | | | — | | | 879 | |
Asset retirement obligation accretion | | — | | | 61 | | | 25 | | | 1 | | | — | | | 87 | |
| | | | | | | | | | | | |
| | 737 | | | 589 | | | 2,756 | | | 11 | | | 89 | | | 4,182 | |
Operating Income (Loss)(2) | | $ | 1,970 | | | $ | 589 | | | $ | 1,960 | | | $ | 10 | | | $ | (108) | | | 4,421 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
Derivative instrument losses, net | | | | | | | | | | | | (138) | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 1,180 | |
Other, net | | | | | | | | | | | | 107 | |
General and administrative | | | | | | | | | | | | (314) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (21) | |
Financing costs, net | | | | | | | | | | | | (303) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 4,932 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Total Assets(3) | | $ | 3,242 | | | $ | 2,185 | | | $ | 7,675 | | | $ | — | | | $ | 527 | | | $ | 13,629 | |
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Oil | | $ | 202 | | | $ | 227 | | | $ | 539 | | | $ | 779 | |
Natural gas | | 23 | | | 26 | | | 73 | | | 87 | |
Natural gas liquids | | — | | | — | | | — | | | 2 | |
(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Overview
APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries. Prior to the BCP Business Combination (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.
The global economy and the energy industry continue to be impacted by the effects of ongoing international conflicts and the coronavirus disease 2019 (COVID-19) pandemic. Uncertainties in the global supply chain and financial markets, including the impact of inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.
APA’s diversified asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. The Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices during the year but are accelerating completion of eight Permian Basin wells and adding a drilling rig in the Delaware Basin in the fourth quarter of 2023. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. The Company anticipates its full-year 2023 upstream capital investment will be approximately $2 billion. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.
In the third quarter of 2023, the Company reported net income attributable to common stock of $459 million, or $1.49 per diluted share, compared to net income of $422 million, or $1.28 per diluted share, in the third quarter of 2022. Results for the third quarter of 2022 were impacted by higher deferred income tax expense related to remeasurement of the Company’s deferred tax liability from increases in the U.K. energy profits levy.
In the first nine months of 2023, the Company reported net income attributable to common stock of $1.1 billion, or $3.50 per diluted share, compared to net income of $3.2 billion, or $9.51 per diluted share, in the first nine months of 2022. Net income for the first nine months of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the first nine months of 2022. Results from the first nine months of 2022 included approximately $1.2 billion of transaction gains recognized for divesting certain non-core mineral rights in the Delaware Basin and completing the BCP Business Combination.
The Company generated $2.1 billion of cash from operating activities during the first nine months of 2023, 41 percent lower than the first nine months of 2022. APA’s lower operating cash flows for the first nine months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 5.5 million shares of its common stock for $208 million and paid $232 million in dividends to APA common stockholders during the first nine months of 2023.
The Company remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns.
•The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
•The Company’s quarterly dividend was increased in the third quarter of 2022 from $0.125 per share to $0.25 per share, representing a return to pre-COVID-19 dividend levels.
•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2023, the Company had repurchased 72.9 million shares of the Company’s common stock. The Company repurchased 0.4 million shares in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares under the Company’s share repurchase programs.
Operational Highlights
Key operational highlights for the quarter include:
United States
•Daily boe production from the Company’s U.S. assets accounted for 55 percent of its total production during the third quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including three rigs in the Southern Midland Basin and two rigs in the Delaware Basin, and drilled and brought online 15 operated wells in the quarter. The Company has contracted a sixth Permian Basin rig, with plans to commence drilling in the fourth quarter of 2023. The Company’s core Midland Basin development program and recently acquired properties in the Delaware Basin continue to represent key growth areas for the U.S. assets.
International
•In Egypt, the Company continued its drilling and workover activity with a heavier focus on oil prospects. The Company averaged 18 drilling rigs and drilled 26 new productive wells during the third quarter of 2023. Third quarter 2023 gross equivalent production in the Company’s Egypt assets increased 2 percent from the third quarter of 2022, and net production decreased 3 percent. The Company averaged 20 workover rigs during the quarter and expects to increase workover activity over the next two quarters.
•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program there is now directed toward safety, base production management, and asset maintenance and integrity.
•During the quarter, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58, offshore Suriname. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an oil production capacity of 200,000 b/d. Detailed engineering studies are anticipated to start by year-end 2023, and a final investment decision is expected by year-end 2024 with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.
Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Production Revenues
Revenue
The Company’s production revenues and respective contribution to total revenues by country were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution |
| | | | | | | | | | | | | | | | |
| | ($ in millions) |
Oil Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 633 | | | 37 | % | | $ | 630 | | | 38 | % | | $ | 1,631 | | | 37 | % | | $ | 1,883 | | | 36 | % |
Egypt(1) | | 724 | | | 43 | % | | 739 | | | 44 | % | | 1,971 | | | 44 | % | | 2,431 | | | 46 | % |
North Sea | | 348 | | | 20 | % | | 303 | | | 18 | % | | 865 | | | 19 | % | | 938 | | | 18 | % |
Total(1) | | $ | 1,705 | | | 100 | % | | $ | 1,672 | | | 100 | % | | $ | 4,467 | | | 100 | % | | $ | 5,252 | | | 100 | % |
| | | | | | | | | | | | | | | | |
Natural Gas Revenues: | | | | | | | | | | | | | | |
United States | | $ | 89 | | | 38 | % | | $ | 300 | | | 70 | % | | $ | 229 | | | 35 | % | | $ | 764 | | | 62 | % |
Egypt(1) | | 81 | | | 34 | % | | 84 | | | 20 | % | | 264 | | | 40 | % | | 270 | | | 22 | % |
North Sea | | 66 | | | 28 | % | | 44 | | | 10 | % | | 165 | | | 25 | % | | 207 | | | 16 | % |
Total(1) | | $ | 236 | | | 100 | % | | $ | 428 | | | 100 | % | | $ | 658 | | | 100 | % | | $ | 1,241 | | | 100 | % |
| | | | | | | | | | | | | | | | |
NGL Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 133 | | | 96 | % | | $ | 197 | | | 98 | % | | $ | 356 | | | 95 | % | | $ | 615 | | | 94 | % |
Egypt(1) | | — | | | — | % | | — | | | — | % | | — | | | — | % | | 6 | | | 1 | % |
North Sea | | 5 | | | 4 | % | | 5 | | | 2 | % | | 19 | | | 5 | % | | 33 | | | 5 | % |
Total(1) | | $ | 138 | | | 100 | % | | $ | 202 | | | 100 | % | | $ | 375 | | | 100 | % | | $ | 654 | | | 100 | % |
| | | | | | | | | | | | | | | | |
Oil and Gas Revenues: | | | | | | | | | | | | | | |
United States | | $ | 855 | | | 41 | % | | $ | 1,127 | | | 49 | % | | $ | 2,216 | | | 40 | % | | $ | 3,262 | | | 46 | % |
Egypt(1) | | 805 | | | 39 | % | | 823 | | | 36 | % | | 2,235 | | | 41 | % | | 2,707 | | | 38 | % |
North Sea | | 419 | | | 20 | % | | 352 | | | 15 | % | | 1,049 | | | 19 | % | | 1,178 | | | 16 | % |
Total(1) | | $ | 2,079 | | | 100 | % | | $ | 2,302 | | | 100 | % | | $ | 5,500 | | | 100 | % | | $ | 7,147 | | | 100 | % |
(1) Includes revenues attributable to a noncontrolling interest in Egypt.
Production
The Company’s production volumes by country were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | Increase (Decrease) | | 2022 | | 2023 | | Increase (Decrease) | | 2022 |
Oil Volume (b/d) | | | | | | | | | | | | |
United States | | 83,584 | | | 16% | | 72,351 | | | 77,198 | | | 12% | | 68,926 | |
Egypt(1)(2) | | 88,521 | | | 9% | | 81,095 | | | 88,038 | | | 5% | | 83,857 | |
North Sea | | 35,680 | | | 42% | | 25,160 | | | 36,070 | | | 17% | | 30,928 | |
Total | | 207,785 | | | 16% | | 178,606 | | | 201,306 | | | 10% | | 183,711 | |
| | | | | | | | | | | | |
Natural Gas Volume (Mcf/d) | | | | | | | | | | | | |
United States | | 454,643 | | | (7)% | | 489,107 | | | 448,838 | | | (5)% | | 474,777 | |
Egypt(1)(2) | | 300,326 | | | (6)% | | 318,945 | | | 331,158 | | | (5)% | | 350,400 | |
North Sea | | 65,168 | | | 246% | | 18,822 | | | 47,665 | | | 43% | | 33,291 | |
Total | | 820,137 | | | (1)% | | 826,874 | | | 827,661 | | | (4)% | | 858,468 | |
| | | | | | | | | | | | |
NGL Volume (b/d) | | | | | | | | | | | | |
United States | | 66,280 | | | 2% | | 64,958 | | | 61,418 | | | (1)% | | 61,990 | |
Egypt(1)(2) | | — | | | NM | | — | | | — | | | NM | | 261 | |
North Sea | | 1,497 | | | 168% | | 558 | | | 1,209 | | | 12% | | 1,080 | |
Total | | 67,777 | | | 3% | | 65,516 | | | 62,627 | | | (1)% | | 63,331 | |
| | | | | | | | | | | | |
BOE per day(3) | | | | | | | | | | | | |
United States | | 225,639 | | | 3% | | 218,826 | | | 213,423 | | | 2% | | 210,045 | |
Egypt(1)(2) | | 138,575 | | | 3% | | 134,253 | | | 143,231 | | | 1% | | 142,518 | |
North Sea(4) | | 48,038 | | | 66% | | 28,855 | | | 45,222 | | | 20% | | 37,557 | |
Total | | 412,252 | | | 8% | | 381,934 | | | 401,876 | | | 3% | | 390,120 | |
(1) Gross oil, natural gas, and NGL production in Egypt were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | | | 2022 | | 2023 | | | | 2022 |
Oil (b/d) | | 144,528 | | | | | 133,607 | | | 141,995 | | | | | 136,476 | |
Natural Gas (Mcf/d) | | 472,744 | | | | | 510,260 | | | 511,430 | | | | | 554,268 | |
NGL (b/d) | | — | | | | | — | | | — | | | | | 397 | |
(2) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | | | 2022 | | 2023 | | | | 2022 |
Oil (b/d) | | 29,514 | | | | | 27,082 | | | 29,369 | | | | | 27,971 | |
Natural Gas (Mcf/d) | | 100,122 | | | | | 106,553 | | | 110,476 | | | | | 116,869 | |
NGL (b/d) | | — | | | | | — | | | — | | | | | 87 | |
(3) The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.
(4) Average sales volumes from the North Sea for the third quarters of 2023 and 2022 were 55,283 boe/d and 36,467 boe/d, respectively, and 47,370 boe/d and 39,362 boe/d for the first nine months of 2023 and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
NM — Not Meaningful
Pricing
The Company’s average selling prices by country were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | Increase (Decrease) | | 2022 | | 2023 | | Increase (Decrease) | | 2022 |
Average Oil Price – Per barrel | | | | | | | | | | | | |
United States | | $ | 82.33 | | | (13)% | | $ | 94.62 | | | $ | 77.40 | | | (23)% | | $ | 100.06 | |
Egypt | | 88.99 | | | (10)% | | 99.04 | | | 82.04 | | | (23)% | | 106.19 | |
North Sea | | 87.70 | | | (14)% | | 101.85 | | | 83.25 | | | (21)% | | 105.59 | |
Total | | 86.15 | | | (12)% | | 97.81 | | | 80.50 | | | (22)% | | 103.81 | |
| | | | | | | | | | | | |
Average Natural Gas Price – Per Mcf | | | | | | | | | | | | |
United States | | $ | 2.12 | | | (68)% | | $ | 6.67 | | | $ | 1.87 | | | (68)% | | $ | 5.89 | |
Egypt | | 2.91 | | | 1% | | 2.87 | | | 2.92 | | | 4% | | 2.82 | |
North Sea | | 10.98 | | | (54)% | | 24.12 | | | 12.83 | | | (48)% | | 24.59 | |
Total | | 3.12 | | | (44)% | | 5.62 | | | 2.91 | | | (45)% | | 5.31 | |
| | | | | | | | | | | | |
Average NGL Price – Per barrel | | | | | | | | | | | | |
United States | | $ | 21.87 | | | (34)% | | $ | 32.97 | | | $ | 21.24 | | | (42)% | | $ | 36.36 | |
Egypt | | — | | | NM | | — | | | — | | | NM | | 76.80 | |
North Sea | | 42.78 | | | (39)% | | 70.42 | | | 47.58 | | | (35)% | | 72.86 | |
Total | | 22.26 | | | (33)% | | 33.39 | | | 21.85 | | | (42)% | | 37.47 | |
NM — Not Meaningful
Third-Quarter 2023 compared to Third-Quarter 2022
Crude Oil Crude oil revenues for the third quarter of 2023 totaled $1.7 billion, a $33 million increase from the comparative 2022 quarter. A 16 percent higher average daily production increased revenues by $233 million compared to the prior-year quarter, while 12 percent decrease in average realized prices decreased third-quarter 2023 oil revenues by $200 million. Crude oil revenues accounted for 82 percent of total oil and gas production revenues and 50 percent of worldwide production in the third quarter of 2023. Crude oil prices realized in the third quarter of 2023 averaged $86.15 per barrel, compared with $97.81 per barrel in the comparative prior-year quarter.
The Company’s worldwide oil production increased 29.2 Mb/d to 207.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity in the U.S. and Egypt, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline across all assets.
Natural Gas Gas revenues for the third quarter of 2023 totaled $236 million, a $192 million decrease from the comparative 2022 quarter. A 44 percent decrease in average realized prices decreased third-quarter 2023 natural gas revenues by $191 million compared to the prior-year quarter, while 1 percent lower average daily production decreased revenues by $1 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2023. The Company’s worldwide natural gas production decreased 6.8 MMcf/d to 820.1 MMcf/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., offset by increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea.
NGL NGL revenues for the third quarter of 2023 totaled $138 million, a $64 million decrease from the comparative 2022 quarter. A 33 percent decrease in average realized prices decreased third-quarter 2023 NGL revenues by $67 million compared to the prior-year quarter, while 3 percent higher average daily production increased revenues by $3 million. NGL revenues accounted for 7 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2023. The Company’s worldwide NGL production increased 2.3 Mb/d to 67.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline.
Year-to-Date 2023 compared to Year-to-Date 2022
Crude Oil Crude oil revenues for the first nine months of 2023 totaled $4.5 billion, a $785 million decrease from the comparative 2022 period. A 22 percent decrease in average realized prices decreased oil revenues for the 2023 period by approximately $1.2 billion compared to the prior-year period, while 10 percent higher average daily production increased revenues by $394 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2023. Crude oil prices realized during the first nine months of 2023 averaged $80.50 per barrel, compared to $103.81 per barrel in the comparative prior-year period.
The Company’s worldwide oil production increased 17.6 Mb/d to 201.3 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.
Natural Gas Gas revenues for the first nine months of 2023 totaled $658 million, a $583 million decrease from the comparative 2022 period. A 45 percent decrease in average realized prices decreased natural gas revenues for the 2023 period by $560 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $23 million compared to the prior-year period. Natural gas revenues accounted for 12 percent of total oil and gas production revenues and 34 percent of worldwide production for the first nine months of 2023. The Company’s worldwide natural gas production decreased 30.8 MMcf/d to 827.7 MMcf/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.
NGL NGL revenues for the first nine months of 2023 totaled $375 million, a $279 million decrease from the comparative 2022 period. A 42 percent decrease in average realized prices decreased NGL revenues for the 2023 period by $273 million compared to the prior-year period, while 1 percent lower average daily production decreased revenues by $6 million compared to the prior-year period. NGL revenues accounted for 7 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2023. The Company’s worldwide NGL production decreased 0.7 Mb/d to 63 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.
Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $229 million and $585 million during the third quarters of 2023 and 2022, respectively, and $612 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $211 million and $573 million during the third quarters of 2023 and 2022, respectively, and $558 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in the third quarter and the first nine months of 2023, primarily due to lower average natural gas prices during the 2023 periods.
Operating Expenses
The Company’s operating expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Lease operating expenses | | $ | 394 | | | $ | 364 | | | $ | 1,076 | | | $ | 1,067 | |
Gathering, processing, and transmission | | 89 | | | 99 | | | 245 | | | 274 | |
Purchased oil and gas costs | | 211 | | | 573 | | | 558 | | | 1,452 | |
Taxes other than income | | 61 | | | 82 | | | 163 | | | 230 | |
Exploration | | 49 | | | 95 | | | 144 | | | 193 | |
General and administrative | | 139 | | | 69 | | | 276 | | | 314 | |
Transaction, reorganization, and separation | | 5 | | | 4 | | | 11 | | | 21 | |
Depreciation, depletion, and amortization: | | | | | | | | |
Oil and gas property and equipment | | 407 | | | 300 | | | 1,086 | | | 847 | |
Gathering, processing, and transmission assets | | 2 | | | 4 | | | 5 | | | 10 | |
Other assets | | 9 | | | 6 | | | 26 | | | 22 | |
Asset retirement obligation accretion | | 29 | | | 29 | | | 86 | | | 87 | |
Impairments | | — | | | — | | | 46 | | | — | |
Financing costs, net | | 81 | | | 75 | | | 235 | | | 303 | |
Total Operating Expenses | | $ | 1,476 | | | $ | 1,700 | | | $ | 3,957 | | | $ | 4,820 | |
Lease Operating Expenses (LOE)
LOE increased $30 million and $9 million compared to the third quarter and the first nine months of 2022, respectively. On a per-unit basis, LOE remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased 2 percent in the first nine months of 2023 when compared to the first nine months of 2022. Overall higher labor costs and other operating costs trending with global inflation drove an increase in absolute LOE, but these increases were primarily offset by decreased workover activity primarily in the North Sea and changes in foreign currency exchange rates against the US dollar.
Gathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Third-party processing and transmission costs | | $ | 63 | | | $ | 71 | | | $ | 164 | | | $ | 205 | |
Midstream service costs – ALTM | | — | | | — | | | — | | | 18 | |
Midstream service costs – Kinetik | | 26 | | | 28 | | | 81 | | | 64 | |
Upstream processing and transmission costs | | 89 | | | 99 | | | 245 | | | 287 | |
Midstream operating expenses | | — | | | — | | | — | | | 5 | |
Intersegment eliminations | | — | | | — | | | — | | | (18) | |
Total Gathering, processing, and transmission | | $ | 89 | | | $ | 99 | | | $ | 245 | | | $ | 274 | |
GPT costs decreased $10 million and $29 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $10 million and $42 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated.
Taxes Other Than Income
Taxes other than income decreased $21 million and $67 million from the third quarter and the first nine months of 2022, respectively, primarily from lower severance taxes driven by lower commodity prices as compared to the prior-year periods.
Exploration Expenses
The Company’s exploration expenses were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Unproved leasehold impairments | | $ | 9 | | | $ | 16 | | | $ | 20 | | | $ | 22 | |
Dry hole expense | | 18 | | | 66 | | | 71 | | | 107 | |
Geological and geophysical expense | | 1 | | | 1 | | | 3 | | | 19 | |
Exploration overhead and other | | 21 | | | 12 | | | 50 | | | 45 | |
Total Exploration | | $ | 49 | | | $ | 95 | | | $ | 144 | | | $ | 193 | |
Exploration expenses decreased $46 million and $49 million from the third quarter and the first nine months of 2022, respectively, primarily the result of higher dry hole expense in Suriname and Egypt during 2022 coupled with lower geological and geophysical expenses. These decreases were partially offset by higher exploration overhead and other activities.
General and Administrative (G&A) Expenses
G&A expenses increased $70 million and decreased $38 million compared to the third quarter and the first nine months of 2022, respectively. The increase in expenses for the third quarter of 2023 compared to the third quarter of 2022 was primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price and anticipated achievement of performance and financial objectives as defined in the stock award plans. G&A expenses for the first nine months of 2022 were higher than the first nine months of 2023, as impacts of anticipated achievement-based objectives and changes in the Company’s stock price on cash-based stock compensation were greater during the first nine months of 2022 than those in the first nine months of 2023.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased $10 million compared to the first nine months of 2022. Higher TRS costs during the first nine months of 2022 were primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2022.
Depreciation, Depletion, and Amortization (DD&A)
Total DD&A expenses increased $108 million and $238 million from the third quarter and the first nine months of 2022, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $2.17 per boe and $1.93 per boe from the third quarter and the first nine months of 2022, respectively, driven by general cost inflation. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and acquisitions in the U.S. over the past year.
Impairments
During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Financing Costs, Net
The Company’s Financing costs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Interest expense | | $ | 89 | | | $ | 80 | | | $ | 266 | | | $ | 249 | |
Amortization of debt issuance costs | | 1 | | | 1 | | | 3 | | | 8 | |
Capitalized interest | | (7) | | | (5) | | | (18) | | | (13) | |
(Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | |
Interest income | | (2) | | | (1) | | | (7) | | | (8) | |
Total Financing costs, net | | $ | 81 | | | $ | 75 | | | $ | 235 | | | $ | 303 | |
Net financing costs increased $6 million and decreased $68 million from the third quarter and the first nine months of 2022, respectively. The increase in costs during the third quarter of 2023 was primarily a result of interest expense on higher outstanding credit facility borrowings compared to the prior-year period. The decrease in costs during the first nine months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first nine months of 2022 and gains on extinguishment of debt in the first nine months of 2023, partially offset by interest expense on higher outstanding credit facility borrowings compared to the prior-year period.
Provision for Income Taxes
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
During the third quarter of 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023.
The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with sustained decreases in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
The Company expects its full-year 2023 estimated upstream capital investment will be approximately $2 billion and remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.
The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for other liquidity and capital resource needs, if required.
For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented:
| | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2023 | | 2022 |
| | | | |
| | (In millions) |
Sources of Cash and Cash Equivalents: | | | | |
Net cash provided by operating activities | | $ | 2,099 | | | $ | 3,530 | |
Proceeds from revolving credit facilities, net | | 202 | | | — | |
Proceeds from asset divestitures | | 29 | | | 778 | |
Proceeds from sale of Kinetik shares | | — | | | 224 | |
| | | | |
| | | | |
Total Sources of Cash and Cash Equivalents | | 2,330 | | | 4,532 | |
Uses of Cash and Cash Equivalents: | | | | |
Additions to upstream oil and gas property | | $ | 1,747 | | | $ | 1,168 | |
Acquisition of Delaware Basin properties | | 24 | | | 563 | |
Leasehold and property acquisitions | | 11 | | | 30 | |
Payments on revolving credit facilities, net | | — | | | 22 | |
Payments on Apache fixed-rate debt | | 65 | | | 1,370 | |
Dividends paid to APA common stockholders | | 232 | | | 127 | |
Distributions to noncontrolling interest – Egypt | | 154 | | | 237 | |
| | | | |
Treasury stock activity, net | | 208 | | | 884 | |
Deconsolidation of Altus cash and cash equivalents | | — | | | 143 | |
Other, net | | 39 | | | 22 | |
Total Uses of Cash and Cash Equivalents | | 2,480 | | | 4,566 | |
Decrease in Cash and Cash Equivalents | | $ | (150) | | | $ | (34) | |
Sources of Cash and Cash Equivalents
Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.
Net cash provided by operating activities during the first nine months of 2023 totaled $2.1 billion, down $1.4 billion from the first nine months of 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items.
For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
Proceeds from Revolving Credit Facilities, Net As of September 30, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $768 million, an increase of $202 million since December 31, 2022.
Proceeds from Asset Divestitures The Company received $29 million and $778 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2023 and 2022, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first nine months of 2022. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Uses of Cash and Cash Equivalents
Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.7 billion and $1.2 billion during the first nine months of 2023 and 2022, respectively. The increase in capital investment is reflective of the increase in the Company’s capital program that has gradually increased over the past year. The Company operated an average of approximately 24 drilling rigs during the first nine months of 2023, compared to an average of approximately 20 drilling rigs during the first nine months of 2022.
Acquisition of Delaware Basin Properties During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. Cash consideration paid during the first nine months of 2022 totaled $563 million.
Leasehold and Property Acquisitions During the first nine months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $11 million and $30 million, respectively.
Payments on Apache Fixed-Rate Debt During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.
Dividends Paid to APA Common Stockholders The Company paid $232 million and $127 million during the first nine months of 2023 and 2022, respectively, for dividends on its common stock. During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.
Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $154 million and $237 million during the first nine months of 2023 and 2022, respectively, in cash distributions to Sinopec.
Treasury Stock Activity, net In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share totaling $208 million, and as of September 30, 2023, the Company had remaining authorization to repurchase 47.1 million shares. In the first nine months of 2022, the Company repurchased 24.0 million shares at an average price of $36.78 per share totaling $884 million.
Liquidity
The following table presents a summary of the Company’s key financial indicators:
| | | | | | | | | | | | | | |
| | September 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Cash and cash equivalents | | $ | 95 | | | $ | 245 | |
Total debt – APA and Apache | | 5,584 | | | 5,453 | |
Total equity | | 2,107 | | | 1,345 | |
Available committed borrowing capacity under syndicated credit facilities | | 2,164 | | | 2,238 | |
Cash and Cash Equivalents As of September 30, 2023, the Company had $95 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.
Debt As of September 30, 2023, the Company had $5.6 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of September 30, 2023, current debt included $2 million of finance lease obligations.
Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).
•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.
Uncommitted Credit Facilities Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023 there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.
Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. There have been no material changes to the contractual obligations described therein.
Potential Decommissioning Obligations on Sold Properties
The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.
By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
As of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.”
Critical Accounting Estimates
The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Some of the more significant estimates include reserve estimates, oil and gas exploration costs, offshore decommissioning contingency, long-lived asset impairments, asset retirement obligations, and income taxes.
New Accounting Pronouncements
There were no material changes in recently issued or adopted accounting standards from those disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the recent conflict in Israel and Gaza, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.
The Company’s average crude oil price realizations decreased 12 percent from $97.81 per barrel to $86.15 per barrel during the third quarters of 2022 and 2023, respectively. The Company’s average natural gas price realizations decreased 44 percent from $5.62 per Mcf to $3.12 per Mcf during the third quarters of 2022 and 2023, respectively. The Company’s average NGL price realizations decreased 33 percent from $33.39 per barrel to $22.26 per barrel during the third quarters of 2022 and 2023, respectively. Based on average daily production for the third quarter of 2023, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $19 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6 million.
The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2023, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $16 million. A 10 percent increase in natural gas prices would decrease the asset by approximately $3 million, while a 10 percent decrease in prices would increase the asset by approximately $3 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2023. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts. Interest Rate Risk
As of September 30, 2023, the Company had $4.8 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.34 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.
The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its syndicated credit facilities. As of September 30, 2023, the Company had approximately $95 million in cash and cash equivalents, approximately 84 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2023, there were $768 million of borrowings outstanding under the Company’s syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments and credit facility borrowings are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.
Foreign Currency Exchange Rate Risk
The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss of $2 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2023.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2023, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.
Changes in Internal Control Over Financial Reporting
There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended September 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 and Note 11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings. ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2023, June 30, 2023, and September 30, 2023 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Issuer Purchases of Equity Securities |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1) | | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1) |
July 1 to July 31, 2023 | | — | | | $ | — | | | — | | | 47,619,742 |
August 1 to August 31, 2023 | | — | | | — | | | — | | | 47,619,742 |
September 1 to September 30, 2023 | | 477,465 | | | 41.90 | | | 477,465 | | | 47,142,277 |
Total | | 477,465 | | $ | 41.90 | | | | | |
(1) During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. During September of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company is not obligated to acquire any specific number of shares.
ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2023, none of the Company’s officers or directors adopted or terminated any Rule 10b5-1 trading arrangement or “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408 of Regulation S-K promulgated under the Securities Act).
ITEM 6. EXHIBITS
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3.1 | – | |
3.2 | – | |
3.3 | – | |
*†10.1 | – | |
*31.1 | – | |
*31.2 | – | |
**32.1 | – | |
*101 | – | The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income, (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags. |
*101.SCH | – | Inline XBRL Taxonomy Schema Document. |
*101.CAL | – | Inline XBRL Calculation Linkbase Document. |
*101.DEF | – | Inline XBRL Definition Linkbase Document. |
*101.LAB | – | Inline XBRL Label Linkbase Document. |
*101.PRE | – | Inline XBRL Presentation Linkbase Document. |
*104 | – | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
* Filed herewith
** Furnished herewith
† Management contracts or compensatory plans or arrangements.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| | | | | | | | | | | |
| | | APA CORPORATION |
| | |
Dated: | November 2, 2023 | | /s/ STEPHEN J. RINEY |
| | | Stephen J. Riney |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | |
Dated: | November 2, 2023 | | /s/ REBECCA A. HOYT |
| | | Rebecca A. Hoyt |
| | | Senior Vice President, Chief Accounting Officer, and Controller |
| | | (Principal Accounting Officer) |
Exhibit 10.1 APA CORPORATION NON-EMPLOYEE DIRECTORS’ COMPENSATION PLAN As Amended and Restated September 12, 2023 PURPOSE The purpose of the Non-Employee Directors’ Compensation Plan (the “Plan”) is to set forth certain of the compensation arrangements for members of the board of directors (the “Board”) of APA Corporation (“APA”) who are not also employees of APA or its subsidiaries (“Non-Employee Directors”). The Plan does not supersede or amend in any way any other arrangements relating to Non-Employee Directors including specifically, without limitation, the Outside Directors’ Retirement Plan, the 2016 Omnibus Compensation Plan, indemnification provisions of APA’s charter or bylaws, or policies with respect to reimbursement of expenses. It is APA’s express intention that this Plan comply with the requirements of Code §409A, and the Plan shall be interpreted in that light. PLAN PROVISIONS 1. Board Retainer. Each Non-Employee Director shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) during which he or she served as a member of APA’s Board (“Cash Retainer Fee”). If a Non-Employee Director serves as a member of APA’s Board for less than an entire calendar quarter, the Cash Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served during that calendar quarter. 2. Non-Executive Chair Retainer. Subject to section 4 below, each Non-Employee Director serving as non-executive chair of APA’s Board shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Non-Executive Chair Retainer Fee”). If a Non-Employee Director serves as non-executive chair for less than an entire calendar quarter, the Non-Executive Chair Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as non-executive chair during that calendar quarter. 3. Committee Chair Retainers. Subject to section 4 below, each Non-Employee Director serving as chair of any committee of APA’s Board shall be paid the fee indicated below at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Committee Chair Retainer Fee”): - Audit Committee - $5,000 - Corporate Responsibility, Governance, and Nominating Committee - $3,750 - Management Development and Compensation Committee - $5,000 - Cybersecurity Committee - $3,750 If a Non-Employee Director serves as chair of any committee of APA’s Board for less than an entire calendar quarter, the applicable Committee Chair Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as chair during that calendar quarter. 4. Combined Non-Executive Chair and Committee Chair Retainer. If the Non-Employee Director serving as non-executive chair of APA’s Board is also serving as chair of any committee
2 of 7 of APA’s Board, the Non-Employee Director shall be paid $25,000 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Combined Retainer Fee”). If a Non-Employee Director serves as both non-executive chair and committee chair for less than an entire calendar quarter, the Combined Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served as both non-executive chair and committee chair during that calendar quarter. 5. Audit Committee Member Retainer. Each Audit Committee member (excluding the chair) shall be paid $1,250 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) during which he or she served as a member of the Audit Committee (“Audit Committee Retainer Fee”). If an Audit Committee member serves as a member of the Audit Committee for less than an entire calendar quarter, the Audit Committee Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served during that calendar quarter. 6. Attendance Fees. No attendance fee shall be paid to any Non-Employee Director for any meeting of the Board or any committee thereof attended in person or by teleconference, video conference, or other similar means. 7. Optional Deferral of Fees. (a) Deferrable Fees. A Non-Employee Director may defer all or any portion of any unpaid Cash Retainer Fees, Non-Executive Chair Retainer Fees, Committee Chair Retainer Fees, and Combined Retainer Fees (“Deferrable Fees”). (b) Election to Defer. A Non-Employee Director’s election to defer all or any portion of Deferrable Fees (“Deferral Election”) shall be effected by the completion of a Deferral Election form. A Deferral Election form must be executed by the deferring Non-Employee Director and received by APA on or before December 31 of the year prior to the year in which the Deferrable Fees are earned, except that a new Non-Employee Director may enter into a Deferral Election within 30 days of becoming a Non-Employee Director. A Deferral Election shall apply only to Deferrable Fees paid for services rendered after the date of the Deferral Election. Each December 31, a Deferral Election made for the following year shall become irrevocable. A new Deferral Election must be made each year for the upcoming year. (c) Memorandum Account. APA shall maintain a separate account (“Memorandum Account”) for each deferring Non-Employee Director. Each Memorandum Account shall be subdivided into a “Cash Account” and a “Stock Account.” The Memorandum Accounts are merely for recordkeeping purposes and do not represent any actual property that has been set aside for Non-Employee Directors. Nothing contained in this Plan shall be construed to require APA to fund any Memorandum Account. Neither the deferring Non-Employee Director nor his or her Beneficiary shall have any property interest whatsoever in any specific assets of APA. A Non-Employee Director shall have no ownership rights with respect to any balance in his or her Memorandum Account and thus shall have no right to vote any Stock in his or her Stock Account. (d) Crediting of Cash Accounts. Any deferred Cash Retainer Fees and deferred Committee Chair Retainer Fees shall be credited to the Cash Account. Any dividends paid on Stock in the Stock Accounts shall be credited to the Cash Account. All amounts credited to a Cash Account shall be credited with investment earnings at the rate of interest earned by APA’s
3 of 7 short-term marketable securities portfolio or an equivalent index or market rate for similar investments in short-term marketable securities. (e) Crediting of Stock Accounts. No deferrals shall be credited to a Stock Account; however, see section 7(f) for transfers from the Cash Account to the Stock Account. All amounts credited to a Stock Account shall be treated as if such amounts were invested in Stock. APA shall at all times have reserved from its treasury shares for issuance under this Plan a number of shares at least equal to the number of shares of Stock in the Stock Accounts. (f) Transfers from Cash Account to Stock Account. Each year, a Non-Employee Director may elect to transfer all or a portion of his or her Cash Account to his or her Stock Account (but only in whole-share increments) by completing an election form that must be received by APA on or before December 31. Any such transfer shall be made as of the first trading day of the following year and shall be based on the per share closing price of the Stock as reported on the Composite Tape for the first trading day of the year. Transfers are not permitted from a Stock Account to a Cash Account. (g) Payout Elections. If a Non-Employee Director’s directorship terminated before January 1, 2005, his or her benefit payments shall be determined under the terms of the Plan on December 31, 2004, and the payout elections in effect at the time his or her directorship terminated. If a Non-Employee Director had a Separation from Service after December 31, 2004, and before January 1, 2009, his or her benefits shall be determined under the terms of the Plan in effect at the time of his or her Separation from Service (defined in paragraph (v) below). The remainder of this section 7(g) shall only apply to individuals who continue as Non- Employee Directors after December 31, 2008, or who become Non-Employee Directors after December 31, 2008. (i) Election. Each individual who is Non-Employee Director on January 1, 2009, has made a payout election for his or her Memorandum Account, which specified both the timing and form of distribution. A new Non-Employee Director shall make a payout election at the same time that he or she makes his or her first Deferral Election. If no payout election is timely made, the Non-Employee Director shall be deemed to have elected to be paid a single lump-sum payment in January after his or her Separation from Service. The payout election with respect to a Memorandum Account is irrevocable after the deadline for making the payout election. The payout election will not apply if there is a change of control (see section 7(h)) or the Non-Employee Director dies (see section 7(i)). (ii) Form of Payout. A Non-Employee Director may elect to be paid out in a single lump- sum payment or in two to ten annual installments. Each installment from a Stock Account shall be equal to the number of shares in the Stock Account on the second trading day of that year, divided by the number of remaining installments, rounded down to the nearest whole share. For example, the first installment from a Stock Account payable in seven installments beginning in 2010 shall be one-seventh of the shares in the account on the second trading day of 2010; the second installment shall be one-sixth of the shares in the account on the second trading date of 2011; etc. Each installment from a Cash Account shall be equal to the balance of the Cash Account on the second trading day of the year, divided by the number of remaining installments, except that the last installment shall equal the balance of the Cash Account at the time the distribution is processed. Distributions from the Stock Account shall be paid in whole shares of Stock. Distributions from the Cash Account shall be paid in cash.
4 of 7 (iii) Timing of Payment(s). A Non-Employee Director may select a specific year in which the single lump-sum payment is made or the installment payments begin (“In-Service Distribution”), in which case the payment will be made as soon as administratively practicable in January of the earlier of the selected year or the year after the Non- Employee Director’s Separation from Service. Alternatively, a Non-Employee Director may elect for his or her single lump-sum payment or first installment to be paid as soon as administratively practicable in the January after his or her Separation from Service. Subsequent installment payments shall be made in January of each year, beginning with the year after the first installment was paid. (iv) Special Rules Where Payments Begin While Still a Director. This paragraph (iv) applies to a Non-Employee Director who elected an In-Service Distribution. A second Memorandum Account shall be established for the Non-Employee Director for any amounts deferred into the Plan during or after the year in which the In-Service Distribution is scheduled to begin. Distributions from the second Memorandum Account shall be subject to the rules specified in this section 7(g), except that a Non-Employee Director must complete a payout election for the second Memorandum Account by the December 31 that immediately precedes the year in which amounts are first deferred into the second Memorandum Account. (v) Definition of Separation from Service. The term “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i), determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, including the special rules for members of a board of directors found in Treasury Regulation §1.409A-1(h)(5) and §1.409A-1(c)(2)(ii). In general, a Separation from Service will occur when a Non-Employee Director ceases to be a member of the Board. (vi) Special Rules for Specified Employees. If a Non-Employee Director is a Specified Employee, (A) any payments under paragraph (iii) above that are triggered by his or her Separation from Service and scheduled to occur within six months after the Separation from Service shall be delayed and paid six months after the Separation from Service, and (B) section 7(h) is modified for a Non-Employee Director whose Separation from Service preceded a change of control by less than six months to provide that the lump sum payment will not occur until six months after the Separation from Service. The term “Specified Employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i) and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A. (h) Change of Control. If there is a change of control of APA that is described in Code §409A(a)(2)(A)(v), each Memorandum Account shall be paid to the appropriate Non- Employee Director (or to the Beneficiary of a deceased Non-Employee Director) in a single lump-sum payment made on the date of the change of control or as soon thereafter as is administratively practicable and in no event later than the end of the calendar year in which the change of control occurs. (i) Beneficiaries. If a Non-Employee Director dies while there is still a balance in his or her Memorandum Account, that amount shall be paid to his or her Beneficiary in a single lump- sum payment that is made as soon as administratively convenient four months after the Non- Employee Director’s death, but in no event later than the end of the calendar year that contains the day that is four months after the Non-Employee Director’s death. This four-month period
5 of 7 is designed to provide the Beneficiary with a sufficient opportunity to disclaim all or part of the benefit, as explained in paragraph (iv) below. No payment shall be made until APA has been furnished with proof of death and such other information as it may reasonably require. (i) Designation. Each Non-Employee Director shall designate one or more persons, trusts, or other entities as his or her beneficiary (“Beneficiary”). In the absence of an effective Beneficiary designation as to part or all of a Memorandum Account, such amount shall be distributed to the Non-Employee Director’s surviving Spouse, if any, otherwise to the Non-Employee Director’s estate. Unless the Non-Employee Director’s Beneficiary designation form specifies otherwise, if a Beneficiary dies after the Non-Employee Director but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate. (ii) Changing Beneficiaries. A Beneficiary designation may be changed by the Non- Employee Director at any time and without the consent of any previously designated Beneficiary. However, if the Non-Employee Director is married, the Non-Employee Director’s Spouse shall be the Beneficiary unless the Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must have been made before January 1, 2005, or, if made on or after January 1, 2005, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with APA. If the Non- Employee Director has designated his or her Spouse as a primary or contingent Beneficiary and the Non-Employee Director and Spouse later divorce (or their marriage is annulled), then the former Spouse will be treated as having pre-deceased the Non- Employee Director for purposes of interpreting a Beneficiary designation form completed prior to the divorce or annulment; this provision will apply only if APA is notified of the divorce or annulment before payment to the former Spouse is made. (iii) “Spouse” shall mean the individual to whom a Non-Employee Director is lawfully married according to the laws of the state of the Non-Employee Director’s domicile. (iv) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary. (j) Adjustments in Stock. In the event of any merger, consolidation, liquidation, dissolution, recapitalization, or reorganization of APA, split, subdivision, or consolidation of shares of Stock, the payment of a stock dividend, or any other material change in APA’s capital structure, the number of shares of Stock shown in each deferring Non-Employee Director’s Stock Account shall be adjusted to reflect that number of shares of Stock or such cash, securities, or other property to which such Non-Employee Director would have been entitled if, immediately prior thereto, such Non-Employee Director had been the holder of record of the number of shares of Stock shown in the Stock Account. Notwithstanding the foregoing, the issuance by APA of Stock, rights, options, or warrants to acquire Stock, or securities convertible or exchangeable into Stock in consideration of cash, property, labor, or services, whether or not for fair value, shall not result in an adjustment pursuant to this section 7(j).
6 of 7 8. Assignment and Transfer. The right of the Non-Employee Director or any other person to receive payments under the Plan shall not be assigned, transferred, pledged, or encumbered. 9. Amendment of Plan. The Plan may be amended from time to time or terminated by vote of the Board. Upon such amendment or termination, Non-Employee Directors shall not be entitled to receive pursuant to the Plan any compensation or other rights or benefits not accrued hereunder prior to the time of amendment or termination hereof; provided, however, that no such Plan amendment or termination shall impair any rights of Non-Employee Directors to amounts previously accrued pursuant to the Plan or accumulated in such Non-Employee Director’s Memorandum Account. A Plan termination shall not affect the timing of any benefit payments from a Memorandum Account; payment may occur substantially after the Plan is terminated. 10. Successors and Assigns. The Plan is binding upon APA and its successors and assigns. The Plan shall continue in effect until terminated by the Board. Any such termination shall operate only prospectively and shall not affect the rights and obligations under elections previously made. 11. Administrative Delays. The Plan shall be administered by the Management Development and Compensation Committee (the “MD&C Committee”) of the Board. The MD&C Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the MD&C Committee. If possible, the delay will satisfy one of the conditions to be considered a permissible delay under Code §409A. 12. 409A Noncompliance. To the extent that APA or the MD&C Committee takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, APA shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put the individual in the same after- tax position he or she would have been in had there been no violation of Code §409A. APA shall not pay a gross-up if the cause of the violation of Code §409A is the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the MD&C Committee - with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively convenient after the MD&C Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation. 13. Notices. Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed: (a) If to APA, to APA Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention: Corporate Secretary) or at such other address as may have been furnished in writing by APA to a Non-Employee Director;
7 of 7 (b) If to a Non-Employee Director or Spouse, at the address the Non-Employee Director has furnished to APA in writing; or (c) If to a Beneficiary, at the address the Non-Employee Director has furnished to APA in writing for such Beneficiary, unless the Beneficiary has furnished his or her own address in writing to APA. Any such notice to a Non-Employee Director, Spouse, or Beneficiary shall be deemed to have been given as of the third day after deposit in the United States Postal Service, postage prepaid, properly addressed as set forth above, in the case of a mailed notice, or as of the date delivered in the case of any other method of delivery. 14. Gender. Any term used herein in the singular shall also include the plural, and the masculine gender shall also include the feminine gender, and vice versa. 15. Statutory References. Any reference to a specific section of the Code shall be deemed to refer to that section or to the appropriate successor section. 16. Governing Law. The Plan shall be governed by the laws of the State of Texas, ignoring any conflicts-of-law provisions. Dated: September 12, 2023 ATTEST: APA CORPORATION /s/ Rajesh Sharma____________ By: /s/ Brandy Jones Rajesh Sharma Brandy Jones Corporate Secretary Vice President, Human Resources
EXHIBIT 31.1
CERTIFICATIONS
I, John J. Christmann IV, certify that:
| | | | | | | | |
1. | I have reviewed this quarterly report on Form 10-Q of APA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: November 2, 2023
| | | | | |
/s/ John J. Christmann IV | |
John J. Christmann IV | |
Chief Executive Officer and President | |
(principal executive officer) | |
EXHIBIT 31.2
CERTIFICATIONS
I, Stephen J. Riney, certify that:
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1. | I have reviewed this quarterly report on Form 10-Q of APA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: November 2, 2023
| | | | | |
/s/ Stephen J. Riney | |
Stephen J. Riney | |
Executive Vice President and Chief Financial Officer | |
(principal financial officer) | |
EXHIBIT 32.1
APA CORPORATION
Certification of Principal Executive Officer
and Principal Financial Officer
I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2023, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.
Date: November 2, 2023
| | | | | | | | | | | |
/s/ John J. Christmann IV | |
By: | | John J. Christmann IV | |
Title: | | Chief Executive Officer and President | |
| | (principal executive officer) | |
I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2023, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.
Date: November 2, 2023
| | | | | | | | | | | |
/s/ Stephen J. Riney | |
By: | | Stephen J. Riney | |
Title: | | Executive Vice President and Chief Financial Officer | |
| | (principal financial officer) | |
v3.23.3
Cover - shares
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9 Months Ended |
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Sep. 30, 2023 |
Oct. 31, 2023 |
Cover [Abstract] |
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Document Type |
10-Q
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Document Quarterly Report |
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Document Period End Date |
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Entity File Number |
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APA CORPORATION
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Entity Incorporation, State or Country Code |
DE
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Entity Tax Identification Number |
86-1430562
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Entity Address, Address Line One |
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
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Houston
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TX
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713
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296-6000
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Title of 12(b) Security |
Common Stock, $0.625 par value
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APA
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NASDAQ
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v3.23.3
STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
REVENUES AND OTHER: |
|
|
|
|
|
Derivative instrument gains (losses), net |
|
$ 0
|
$ (44)
|
$ 104
|
$ (138)
|
Gain on divestitures, net |
|
1
|
31
|
7
|
1,180
|
Other, net |
|
0
|
(2)
|
77
|
107
|
Total revenues and other |
|
2,309
|
2,872
|
6,300
|
9,752
|
OPERATING EXPENSES: |
|
|
|
|
|
Lease operating expenses |
|
394
|
364
|
1,076
|
1,067
|
Taxes other than income |
|
61
|
82
|
163
|
230
|
Exploration |
|
49
|
95
|
144
|
193
|
General and administrative |
|
139
|
69
|
276
|
314
|
Transaction, reorganization, and separation |
|
5
|
4
|
11
|
21
|
Depreciation, depletion, and amortization |
|
418
|
310
|
1,117
|
879
|
Asset retirement obligation accretion |
|
29
|
29
|
86
|
87
|
Impairments |
|
0
|
0
|
46
|
0
|
Financing costs, net |
|
81
|
75
|
235
|
303
|
Total operating expenses |
|
1,476
|
1,700
|
3,957
|
4,820
|
NET INCOME BEFORE INCOME TAXES |
|
833
|
1,172
|
2,343
|
4,932
|
Current income tax provision |
|
422
|
357
|
1,022
|
1,164
|
Deferred income tax provision (benefit) |
|
(144)
|
285
|
(22)
|
225
|
NET INCOME INCLUDING NONCONTROLLING INTERESTS |
|
555
|
530
|
1,343
|
3,543
|
Net loss attributable to Altus Preferred Unit limited partners |
|
0
|
0
|
0
|
(70)
|
NET INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ 459
|
$ 422
|
$ 1,082
|
$ 3,231
|
NET INCOME PER COMMON SHARE: |
|
|
|
|
|
Basic (in USD per share) |
|
$ 1.49
|
$ 1.28
|
$ 3.50
|
$ 9.54
|
Diluted (in USD per share) |
|
$ 1.49
|
$ 1.28
|
$ 3.50
|
$ 9.51
|
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: |
|
|
|
|
|
Basic (in shares) |
|
308
|
329
|
309
|
339
|
Diluted (in shares) |
|
308
|
330
|
309
|
340
|
Noncontrolling interest – Egypt |
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
$ 96
|
$ 108
|
$ 261
|
$ 368
|
Noncontrolling interest - Altus |
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
0
|
0
|
0
|
14
|
Oil and gas |
|
|
|
|
|
REVENUES AND OTHER: |
|
|
|
|
|
Total revenues |
|
2,308
|
2,887
|
6,112
|
8,603
|
Gathering, processing, and transmission costs |
|
|
|
|
|
REVENUES AND OTHER: |
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
[1] |
2,079
|
2,302
|
5,500
|
7,147
|
OPERATING EXPENSES: |
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
[1] |
89
|
99
|
245
|
274
|
Purchased oil and gas sales |
|
|
|
|
|
REVENUES AND OTHER: |
|
|
|
|
|
Purchased oil and gas sales |
[1] |
229
|
585
|
612
|
1,456
|
OPERATING EXPENSES: |
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
[1] |
$ 211
|
$ 573
|
$ 558
|
$ 1,452
|
|
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v3.23.3
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
NET INCOME INCLUDING NONCONTROLLING INTERESTS |
$ 555
|
$ 530
|
$ 1,343
|
$ 3,543
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: |
|
|
|
|
Pension and postretirement benefit plan |
0
|
0
|
3
|
(1)
|
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS |
555
|
530
|
1,346
|
3,542
|
Comprehensive loss attributable to Altus Preferred Unit limited partners |
0
|
0
|
0
|
(70)
|
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK |
459
|
422
|
1,085
|
3,230
|
Noncontrolling interest – Egypt |
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: |
|
|
|
|
Comprehensive income attributable to noncontrolling interest |
96
|
108
|
261
|
368
|
Noncontrolling interest - Altus |
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: |
|
|
|
|
Comprehensive income attributable to noncontrolling interest |
$ 0
|
$ 0
|
$ 0
|
$ 14
|
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v3.23.3
STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
Net income including noncontrolling interests |
$ 1,343
|
$ 3,543
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
Unrealized derivative instrument (gains) losses, net |
(61)
|
119
|
Gain on divestitures, net |
(7)
|
(1,180)
|
Exploratory dry hole expense and unproved leasehold impairments |
91
|
129
|
Depreciation, depletion, and amortization |
1,117
|
879
|
Asset retirement obligation accretion |
86
|
87
|
Impairments |
46
|
0
|
Provision for (benefit from) deferred income taxes |
(22)
|
225
|
(Gain) loss on extinguishment of debt |
(9)
|
67
|
Other, net |
(45)
|
(91)
|
Changes in operating assets and liabilities: |
|
|
Receivables |
(289)
|
(554)
|
Inventories |
19
|
(81)
|
Drilling advances and other current assets |
40
|
7
|
Deferred charges and other long-term assets |
227
|
(3)
|
Accounts payable |
(2)
|
175
|
Accrued expenses |
1
|
249
|
Deferred credits and noncurrent liabilities |
(436)
|
(41)
|
NET CASH PROVIDED BY OPERATING ACTIVITIES |
2,099
|
3,530
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
Additions to upstream oil and gas property |
(1,747)
|
(1,168)
|
Acquisition of Delaware Basin properties |
(24)
|
(563)
|
Leasehold and property acquisitions |
(11)
|
(30)
|
Proceeds from sale of oil and gas properties |
29
|
778
|
Proceeds from sale of Kinetik shares |
0
|
224
|
Deconsolidation of Altus cash and cash equivalents |
0
|
(143)
|
Other, net |
(29)
|
8
|
NET CASH USED IN INVESTING ACTIVITIES |
(1,782)
|
(894)
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
Proceeds from (payments on) revolving credit facilities, net |
202
|
(22)
|
Payments on Apache fixed-rate debt |
(65)
|
(1,370)
|
Distributions to noncontrolling interest – Egypt |
(154)
|
(237)
|
Treasury stock activity, net |
(208)
|
(884)
|
Dividends paid to APA common stockholders |
(232)
|
(127)
|
Other, net |
(10)
|
(30)
|
NET CASH USED IN FINANCING ACTIVITIES |
(467)
|
(2,670)
|
NET DECREASE IN CASH AND CASH EQUIVALENTS |
(150)
|
(34)
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
245
|
302
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
95
|
268
|
SUPPLEMENTARY CASH FLOW DATA: |
|
|
Interest paid, net of capitalized interest |
278
|
274
|
Income taxes paid, net of refunds |
$ 867
|
$ 1,029
|
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v3.23.3
CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions |
Sep. 30, 2023 |
Dec. 31, 2022 |
CURRENT ASSETS: |
|
|
Cash and cash equivalents |
$ 95
|
$ 245
|
Receivables, net of allowance of $103 and $117 |
1,753
|
1,466
|
Other current assets (Note 5) |
952
|
997
|
Total current assets |
2,800
|
2,708
|
PROPERTY AND EQUIPMENT: |
|
|
Oil and gas properties |
43,908
|
42,356
|
Gathering, processing, and transmission facilities |
447
|
449
|
Other |
613
|
613
|
Less: Accumulated depreciation, depletion, and amortization |
(35,468)
|
(34,406)
|
Property and equipment, net |
9,500
|
9,012
|
OTHER ASSETS: |
|
|
Equity method interests (Note 6) |
681
|
624
|
Decommissioning security for sold Gulf of Mexico properties (Note 11) |
38
|
217
|
Deferred charges and other |
526
|
586
|
Assets |
13,545
|
13,147
|
CURRENT LIABILITIES: |
|
|
Accounts payable |
741
|
771
|
Current debt |
2
|
2
|
Other current liabilities (Note 7) |
1,892
|
2,143
|
Total current liabilities |
2,635
|
2,916
|
LONG-TERM DEBT (Note 9) |
5,582
|
5,451
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: |
|
|
Income taxes |
305
|
314
|
Asset retirement obligation (Note 8) |
2,006
|
1,940
|
Decommissioning contingency for sold Gulf of Mexico properties (Note 11) |
470
|
738
|
Other |
440
|
443
|
Total deferred credits and other noncurrent liabilities |
3,221
|
3,435
|
EQUITY: |
|
|
Common stock, $0.625 par, 860,000,000 shares authorized, 420,593,611 and 419,869,987 shares issued, respectively |
263
|
262
|
Paid-in capital |
11,197
|
11,420
|
Accumulated deficit |
(4,732)
|
(5,814)
|
Treasury stock, at cost, 113,797,342 and 108,310,838 shares, respectively |
(5,667)
|
(5,459)
|
Accumulated other comprehensive income |
17
|
14
|
APA SHAREHOLDERS’ EQUITY |
1,078
|
423
|
TOTAL EQUITY |
2,107
|
1,345
|
TOTAL LIABILITIES AND EQUITY |
13,545
|
13,147
|
Noncontrolling interest – Egypt |
|
|
EQUITY: |
|
|
Noncontrolling interest – Egypt |
$ 1,029
|
$ 922
|
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v3.23.3
CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions |
Sep. 30, 2023 |
Dec. 31, 2022 |
Statement of Financial Position [Abstract] |
|
|
Receivables, allowance |
$ 103
|
$ 117
|
Common stock, par value (in USD per share) |
$ 0.625
|
$ 0.625
|
Common stock, shares authorized (in shares) |
860,000,000
|
860,000,000
|
Common stock, shares issued (in shares) |
420,593,611
|
419,869,987
|
Treasury stock, shares (in shares) |
113,797,342
|
108,310,838
|
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- DefinitionAmount of allowance for credit loss on accounts receivable, classified as current.
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v3.23.3
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS (Unaudited) - USD ($) $ in Millions |
Total |
Noncontrolling interest – Egypt |
Noncontrolling interest - Altus |
APA SHAREHOLDERS’ EQUITY |
Common Stock |
Paid-In Capital |
Accumulated Deficit |
Treasury Stock |
Accumulated Other Comprehensive Income |
Noncontrolling Interests |
Noncontrolling Interests
Noncontrolling interest – Egypt
|
Noncontrolling Interests
Noncontrolling interest - Altus
|
[1] |
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners |
Beginning balance at Dec. 31, 2021 |
[1] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 712
|
|
Increase (Decrease) in Temporary Equity [Roll Forward] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Altus Preferred Unit limited partners |
[1] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(70)
|
|
Deconsolidation of Altus |
|
|
|
$ (72)
|
|
|
|
|
|
|
|
|
|
|
$ (72)
|
(642)
|
[1] |
Ending balance at Sep. 30, 2022 |
[1] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0
|
|
Beginning balance at Dec. 31, 2021 |
|
$ (717)
|
|
|
$ (1,595)
|
$ 262
|
$ 11,645
|
$ (9,488)
|
$ (4,036)
|
$ 22
|
$ 878
|
[1] |
|
|
|
|
|
Increase (Decrease) in Stockholders' Equity [Roll Forward] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stock |
|
3,231
|
|
|
3,231
|
|
|
3,231
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
|
$ 368
|
14
|
|
|
|
|
|
|
|
|
$ 368
|
[1] |
14
|
|
|
Distributions to noncontrolling interest |
|
|
(237)
|
|
|
|
|
|
|
|
|
|
(237)
|
[1] |
|
|
|
Common dividends declared |
|
(165)
|
|
|
(165)
|
|
(165)
|
|
|
|
|
|
|
|
|
|
|
Deconsolidation of Altus |
|
|
|
(72)
|
|
|
|
|
|
|
|
|
|
|
$ (72)
|
(642)
|
[1] |
Treasury stock activity, net |
|
(884)
|
|
|
(884)
|
|
|
|
(884)
|
|
|
|
|
|
|
|
|
Other |
|
13
|
|
|
13
|
|
14
|
|
|
(1)
|
|
|
|
|
|
|
|
Ending balance at Sep. 30, 2022 |
|
1,551
|
|
|
600
|
262
|
11,494
|
(6,257)
|
(4,920)
|
21
|
951
|
[2] |
|
|
|
|
|
Ending balance at Sep. 30, 2022 |
[1] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 0
|
|
Beginning balance at Jun. 30, 2022 |
|
1,505
|
|
|
584
|
262
|
11,567
|
(6,679)
|
(4,587)
|
21
|
921
|
[2] |
|
|
|
|
|
Increase (Decrease) in Stockholders' Equity [Roll Forward] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stock |
|
422
|
|
|
422
|
|
|
422
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
|
108
|
0
|
|
|
|
|
|
|
|
|
108
|
[2] |
|
|
|
Distributions to noncontrolling interest |
|
|
(78)
|
|
|
|
|
|
|
|
|
|
(78)
|
[2] |
|
|
|
Common dividends declared |
|
(80)
|
|
|
(80)
|
|
(80)
|
|
|
|
|
|
|
|
|
|
|
Treasury stock activity, net |
|
(333)
|
|
|
(333)
|
|
|
|
(333)
|
|
|
|
|
|
|
|
|
Other |
|
7
|
|
|
7
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Ending balance at Sep. 30, 2022 |
|
1,551
|
|
|
600
|
262
|
11,494
|
(6,257)
|
(4,920)
|
21
|
951
|
[2] |
|
|
|
|
|
Beginning balance at Dec. 31, 2022 |
|
1,345
|
|
|
423
|
262
|
11,420
|
(5,814)
|
(5,459)
|
14
|
922
|
[1] |
|
|
|
|
|
Increase (Decrease) in Stockholders' Equity [Roll Forward] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stock |
|
1,082
|
|
|
1,082
|
|
|
1,082
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
|
261
|
0
|
|
|
|
|
|
|
|
|
261
|
[1] |
|
|
|
Distributions to noncontrolling interest |
|
|
(154)
|
|
|
|
|
|
|
|
|
|
(154)
|
[1] |
|
|
|
Common dividends declared |
|
(232)
|
|
|
(232)
|
|
(232)
|
|
|
|
|
|
|
|
|
|
|
Treasury stock activity, net |
|
(208)
|
|
|
(208)
|
|
|
|
(208)
|
|
|
|
|
|
|
|
|
Other |
|
13
|
|
|
13
|
1
|
9
|
|
|
3
|
|
|
|
|
|
|
|
Ending balance at Sep. 30, 2023 |
|
2,107
|
|
|
1,078
|
263
|
11,197
|
(4,732)
|
(5,667)
|
17
|
1,029
|
[2] |
|
|
|
|
|
Beginning balance at Jun. 30, 2023 |
|
1,696
|
|
|
709
|
263
|
11,267
|
(5,191)
|
(5,647)
|
17
|
987
|
[2] |
|
|
|
|
|
Increase (Decrease) in Stockholders' Equity [Roll Forward] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stock |
|
459
|
|
|
459
|
|
|
459
|
|
|
|
|
|
|
|
|
|
Net income attributable to noncontrolling interest |
|
|
96
|
$ 0
|
|
|
|
|
|
|
|
|
96
|
[2] |
|
|
|
Distributions to noncontrolling interest |
|
|
$ (54)
|
|
|
|
|
|
|
|
|
|
$ (54)
|
[2] |
|
|
|
Common dividends declared |
|
(77)
|
|
|
(77)
|
|
(77)
|
|
|
|
|
|
|
|
|
|
|
Treasury stock activity, net |
|
(20)
|
|
|
(20)
|
|
|
|
(20)
|
|
|
|
|
|
|
|
|
Other |
|
7
|
|
|
7
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Ending balance at Sep. 30, 2023 |
|
$ 2,107
|
|
|
$ 1,078
|
$ 263
|
$ 11,197
|
$ (4,732)
|
$ (5,667)
|
$ 17
|
$ 1,029
|
[2] |
|
|
|
|
|
|
|
X |
- DefinitionAmount of paid and unpaid common stock dividends declared with the form of settlement in cash.
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- DefinitionAggregate dividends declared during the period for each share of common stock outstanding.
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v3.23.3
NATURE OF OPERATIONS
|
9 Months Ended |
Sep. 30, 2023 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] |
|
NATURE OF OPERATIONS |
These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, which contains a summary of the Company’s significant accounting policies and other disclosures.
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v3.23.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
9 Months Ended |
Sep. 30, 2023 |
Accounting Policies [Abstract] |
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES As of September 30, 2023, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail. Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom. Fair Value Measurements Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). During the three and nine months ended September 30, 2023 and 2022, the Company recorded no asset impairments in connection with fair value assessments. Revenue Recognition There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period. Inventories Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value. During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date. Oil and Gas Property The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost. Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail. Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. 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.
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- DefinitionThe entire disclosure for all significant accounting policies of the reporting entity.
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v3.23.3
ACQUISITIONS AND DIVESTITURES
|
9 Months Ended |
Sep. 30, 2023 |
Business Combination and Asset Acquisition [Abstract] |
|
ACQUISITIONS AND DIVESTITURES |
ACQUISITIONS AND DIVESTITURES 2023 Activity During the third quarter and first nine months of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $1 million and $11 million, respectively. During the third quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $1 million and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions. 2022 Activity During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations. During the third quarter and first nine months of 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $3 million and $30 million, respectively. During the third quarter and first nine months of 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $37 million and $52 million, respectively, recognizing a gain of approximately $34 million and $36 million, respectively, upon closing of these transactions. During the first nine months of 2022, the Company completed a transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million. The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s share of ALTM’s deconsolidated balance sheet of $193 million and the fair value of $802 million of its approximate 20 percent retained ownership in the combined entity. During the first quarter of 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and recognized a loss of $25 million, including transaction fees. Refer to Note 6—Equity Method Interests for further detail.
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v3.23.3
CAPITALIZED EXPLORATORY WELL COSTS
|
9 Months Ended |
Sep. 30, 2023 |
Extractive Industries [Abstract] |
|
CAPITALIZED EXPLORATORY WELL COSTS |
CAPITALIZED EXPLORATORY WELL COSTS The Company’s capitalized exploratory well costs were $541 million and $474 million as of September 30, 2023 and December 31, 2022, respectively. The increase is attributable to additional drilling activity offshore Suriname and in Egypt. Approximately $5 million of suspended well costs previously capitalized for greater than one year at December 31, 2022 were charged to dry hole expense during the third quarter of 2023. Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.
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- DefinitionThe entire disclosure for parts or all of the information related to suspended well costs.
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v3.23.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
|
9 Months Ended |
Sep. 30, 2023 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES |
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Objectives and Strategies The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values. Counterparty Risk The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023, the Company had derivative positions with seven counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates. Derivative Instruments Commodity Derivative Instruments As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Basis Swap Purchased | | Basis Swap Sold | Production Period | | Settlement Index | | MMBtu (in 000’s) | | Weighted Average Price Differential | | MMBtu (in 000’s) | | Weighted Average Price Differential | October—December 2023 | | NYMEX Henry Hub/IF Waha | | 18,400 | | | $(1.15) | | — | | | — | October—December 2023 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 18,400 | | | $(0.08) | January—June 2024 | | NYMEX Henry Hub/IF Waha | | 16,380 | | | $(1.15) | | — | | | — | January—June 2024 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 16,380 | | | $(0.10) |
Fair Value Measurements The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using | | | | | | | | | Quoted Price in Active Markets (Level 1) | | Significant Other Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value | | Netting(1) | | Carrying Amount | | | | | | | | | | | | | | | | (In millions) | September 30, 2023 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | Liabilities: | | | | | | | | | | | | | Commodity derivative instruments | | — | | | 50 | | | — | | | 50 | | | — | | | 50 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances. The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement. Derivative Activity Recorded in the Consolidated Balance Sheet All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Current Assets: Other current assets | | $ | 16 | | | $ | — | | Other Assets: Deferred charges and other | | — | | | 5 | | Total derivative assets | | $ | 16 | | | $ | 5 | | | | | | | Current Liabilities: Other current liabilities | | $ | — | | | $ | 50 | | | | | | | Total derivative liabilities | | $ | — | | | $ | 50 | |
Derivative Activity Recorded in the Statement of Consolidated Operations The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Realized: | | | | | | | | | Commodity derivative instruments | | $ | 19 | | | $ | (2) | | | $ | 43 | | | $ | (11) | | Foreign currency derivative instruments | | — | | | (6) | | | — | | | (8) | | Realized gains (losses), net | | 19 | | | (8) | | | 43 | | | (19) | | Unrealized: | | | | | | | | | Commodity derivative instruments | | (19) | | | (35) | | | 61 | | | (79) | | | | | | | | | | | Foreign currency derivative instruments | | — | | | (1) | | | — | | | (9) | | Preferred Units embedded derivative | | — | | | — | | | — | | | (31) | | Unrealized gains (losses), net | | (19) | | | (36) | | | 61 | | | (119) | | Derivative instrument gains (losses), net | | $ | — | | | $ | (44) | | | $ | 104 | | | $ | (138) | |
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
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v3.23.3
EQUITY METHOD INTERESTS
|
9 Months Ended |
Sep. 30, 2023 |
Equity Method Investments and Joint Ventures [Abstract] |
|
EQUITY METHOD INTERESTS |
EQUITY METHOD INTERESTS The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations. The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares. The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock. The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49 million in the first nine months of 2023 and 2022, respectively. These gains and losses were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations. The following table represents sales and costs associated with Kinetik: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Natural gas and NGLs sales | | $ | 35 | | | $ | — | | | $ | 78 | | | $ | — | | Purchased oil and gas sales | | 11 | | | — | | | 18 | | | — | | | | $ | 46 | | | $ | — | | | $ | 96 | | | $ | — | | | | | | | | | | | Gathering, processing, and transmission costs | | $ | 26 | | | $ | 28 | | | $ | 81 | | | $ | 64 | | Purchased oil and gas costs | | 37 | | | — | | | 65 | | | — | | | | $ | 63 | | | $ | 28 | | | $ | 146 | | | $ | 64 | |
As of September 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $43 million and receivables from Kinetik of approximately $29 million.
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v3.23.3
OTHER CURRENT LIABILITIES
|
9 Months Ended |
Sep. 30, 2023 |
Payables and Accruals [Abstract] |
|
OTHER CURRENT LIABILITIES |
OTHER CURRENT LIABILITIES The following table provides detail of the Company’s other current liabilities: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Accrued operating expenses | | $ | 161 | | | $ | 145 | | Accrued exploration and development | | 328 | | | 333 | | Accrued compensation and benefits | | 379 | | | 514 | | Accrued interest | | 66 | | | 97 | | Accrued income taxes | | 228 | | | 90 | | Current asset retirement obligation | | 55 | | | 55 | | Current operating lease liability | | 108 | | | 167 | | | | | | | Current decommissioning contingency for sold Gulf of Mexico properties | | 225 | | | 450 | | Other | | 342 | | | 292 | | Total Other current liabilities | | $ | 1,892 | | | $ | 2,143 | |
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v3.23.3
ASSET RETIREMENT OBLIGATION
|
9 Months Ended |
Sep. 30, 2023 |
Asset Retirement Obligation Disclosure [Abstract] |
|
ASSET RETIREMENT OBLIGATION |
ASSET RETIREMENT OBLIGATION The following table describes changes to the Company’s asset retirement obligation (ARO) liability: | | | | | | | | | | | September 30, 2023 | | | (In millions) | Asset retirement obligation, December 31, 2022 | | $ | 1,995 | | Liabilities incurred | | 14 | | | | | Liabilities settled | | (34) | | | | | | | | | | | Accretion expense | | 86 | | | | | Asset retirement obligation, September 30, 2023 | | 2,061 | | Less current portion | | (55) | | Asset retirement obligation, long-term | | $ | 2,006 | |
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v3.23.3
DEBT AND FINANCING COSTS
|
9 Months Ended |
Sep. 30, 2023 |
Debt Disclosure [Abstract] |
|
DEBT AND FINANCING COSTS |
DEBT AND FINANCING COSTS The following table presents the carrying values of the Company’s debt: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Apache notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 4,835 | | | $ | 4,908 | | | | | | | Syndicated credit facilities(2) | | 768 | | | 566 | | Apache finance lease obligations | | 33 | | | 34 | | Unamortized discount | | (26) | | | (27) | | Debt issuance costs | | (26) | | | (28) | | Total debt | | 5,584 | | | 5,453 | | Current maturities | | (2) | | | (2) | | Long-term debt | | $ | 5,582 | | | $ | 5,451 | |
(1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively. The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates. At each of September 30, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations. During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility. During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility. On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility. On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility). •One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options. •The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion. As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020. Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023, there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities. Financing Costs, Net The following table presents the components of the Company’s financing costs, net: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Interest expense | | $ | 89 | | | $ | 80 | | | $ | 266 | | | $ | 249 | | Amortization of debt issuance costs | | 1 | | | 1 | | | 3 | | | 8 | | Capitalized interest | | (7) | | | (5) | | | (18) | | | (13) | | (Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | | Interest income | | (2) | | | (1) | | | (7) | | | (8) | | Financing costs, net | | $ | 81 | | | $ | 75 | | | $ | 235 | | | $ | 303 | |
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- DefinitionThe entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.
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v3.23.3
INCOME TAXES
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9 Months Ended |
Sep. 30, 2023 |
Income Tax Disclosure [Abstract] |
|
INCOME TAXES |
INCOME TAXESThe Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur. During the third quarter of 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability. On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023. The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded. The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
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- DefinitionThe entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.
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v3.23.3
COMMITMENTS AND CONTINGENCIES
|
9 Months Ended |
Sep. 30, 2023 |
Commitments and Contingencies Disclosure [Abstract] |
|
COMMITMENTS AND CONTINGENCIES |
COMMITMENTS AND CONTINGENCIES Legal Matters The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2023, the Company has an accrued liability of approximately $49 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity. For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Argentine Environmental Claims On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer. Louisiana Restoration As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims. Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims. Apollo Exploration Lawsuit In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings. Australian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims. Canadian Operations Divestiture Dispute Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized by the end of 2023. California and Delaware Litigation On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit. Kulp Minerals Lawsuit On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit. Shareholder and Derivative Lawsuits On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company intends to vigorously defend this lawsuit. On January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, on February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits. Environmental Matters As of September 30, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million. On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings. The Company is not aware of any environmental claims existing as of September 30, 2023, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties. Potential Decommissioning Obligations on Sold Properties In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets. On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets. As of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit. As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.” On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Apache intends to vigorously defend these claims, and will vigorously pursue its counterclaims.
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v3.23.3
CAPITAL STOCK
|
9 Months Ended |
Sep. 30, 2023 |
Equity [Abstract] |
|
CAPITAL STOCK |
CAPITAL STOCK Net Income per Common Share The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | | 2023 | | 2022 | | | Income | | Shares | | Per Share | | Income | | Shares | | Per Share | | | | | | | | | | | | | | | | (In millions, except per share amounts) | Basic: | | | | | | | | | | | | | Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 329 | | | $ | 1.28 | | Effect of Dilutive Securities: | | | | | | | | | | | | | Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | — | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 330 | | | $ | 1.28 | | | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | | Income | | Shares | | Per Share | | Income | | Shares | | Per Share | | | | | | | | | | | | | | | | (In millions, except per share amounts) | Basic: | | | | | | | | | | | | | Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 339 | | | $ | 9.54 | | Effect of Dilutive Securities: | | | | | | | | | | | | | Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | (0.03) | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 340 | | | $ | 9.51 | |
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.7 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.5 million during the first nine months of 2023 and 2022, respectively. Stock Repurchase Program During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock. In the third quarter of 2023, the Company repurchased approximately 0.5 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share, and as of September 30, 2023, the Company had remaining authorization to repurchase up to 47.1 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share. The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares. The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions. Common Stock Dividend For the quarters ended September 30, 2023 and 2022, the Company paid $77 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127 million, respectively, in dividends on its common stock. During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.
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v3.23.3
BUSINESS SEGMENT INFORMATION
|
9 Months Ended |
Sep. 30, 2023 |
Segment Reporting [Abstract] |
|
BUSINESS SEGMENT INFORMATION |
BUSINESS SEGMENT INFORMATION As of September 30, 2023, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total | | | Upstream | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, 2023 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 724 | | | $ | 348 | | | $ | 633 | | | $ | — | | | $ | — | | | $ | 1,705 | | Natural gas revenues | | 81 | | | 66 | | | 89 | | | — | | | — | | | 236 | | Natural gas liquids revenues | | — | | | 5 | | | 133 | | | — | | | — | | | 138 | | Oil, natural gas, and natural gas liquids production revenues | | 805 | | | 419 | | | 855 | | | — | | | — | | | 2,079 | | Purchased oil and gas sales | | — | | | — | | | 229 | | | — | | | — | | | 229 | | | | | | | | | | | | | | | | | 805 | | | 419 | | | 1,084 | | | — | | | — | | | 2,308 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 128 | | | 102 | | | 164 | | | — | | | — | | | 394 | | Gathering, processing, and transmission | | 13 | | | 15 | | | 61 | | | — | | | — | | | 89 | | Purchased oil and gas costs | | — | | | — | | | 211 | | | — | | | — | | | 211 | | Taxes other than income | | — | | | — | | | 61 | | | — | | | — | | | 61 | | Exploration | | 25 | | | 9 | | | 4 | | | — | | | 11 | | | 49 | | Depreciation, depletion, and amortization | | 129 | | | 90 | | | 199 | | | — | | | — | | | 418 | | Asset retirement obligation accretion | | — | | | 20 | | | 9 | | | — | | | — | | | 29 | | | | | | | | | | | | | | | | | 295 | | | 236 | | | 709 | | | — | | | 11 | | | 1,251 | | Operating Income (Loss)(2) | | $ | 510 | | | $ | 183 | | | $ | 375 | | | $ | — | | | $ | (11) | | | 1,057 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | General and administrative | | | | | | | | | | | | (139) | | Transaction, reorganization, and separation | | | | | | | | | | | | (5) | | Financing costs, net | | | | | | | | | | | | (81) | | Income Before Income Taxes | | | | | | | | | | | | $ | 833 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2023 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 1,971 | | | $ | 865 | | | $ | 1,631 | | | $ | — | | | $ | — | | | $ | 4,467 | | Natural gas revenues | | 264 | | | 165 | | | 229 | | | — | | | — | | | 658 | | Natural gas liquids revenues | | — | | | 19 | | | 356 | | | — | | | — | | | 375 | | Oil, natural gas, and natural gas liquids production revenues | | 2,235 | | | 1,049 | | | 2,216 | | | — | | | — | | | 5,500 | | Purchased oil and gas sales | | — | | | — | | | 612 | | | — | | | — | | | 612 | | | | | | | | | | | | | | | | | 2,235 | | | 1,049 | | | 2,828 | | | — | | | — | | | 6,112 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 346 | | | 278 | | | 452 | | | — | | | — | | | 1,076 | | Gathering, processing, and transmission | | 26 | | | 38 | | | 181 | | | — | | | — | | | 245 | | Purchased oil and gas costs | | — | | | — | | | 558 | | | — | | | — | | | 558 | | Taxes other than income | | — | | | — | | | 163 | | | — | | | — | | | 163 | | Exploration | | 91 | | | 18 | | | 10 | | | — | | | 25 | | | 144 | | Depreciation, depletion, and amortization | | 378 | | | 209 | | | 530 | | | — | | | — | | | 1,117 | | Asset retirement obligation accretion | | — | | | 57 | | | 29 | | | — | | | — | | | 86 | | Impairments | | — | | | 46 | | | — | | | — | | | — | | | 46 | | | | 841 | | | 646 | | | 1,923 | | | — | | | 25 | | | 3,435 | | Operating Income (Loss)(2) | | $ | 1,394 | | | $ | 403 | | | $ | 905 | | | $ | — | | | $ | (25) | | | 2,677 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | Derivative instrument gains, net | | | | | | | | | | | | 104 | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 7 | | Other, net | | | | | | | | | | | | 77 | | General and administrative | | | | | | | | | | | | (276) | | Transaction, reorganization, and separation | | | | | | | | | | | | (11) | | Financing costs, net | | | | | | | | | | | | (235) | | Income Before Income Taxes | | | | | | | | | | | | $ | 2,343 | | | | | | | | | | | | | | | Total Assets(3) | | $ | 3,518 | | | $ | 1,665 | | | $ | 7,827 | | | $ | — | | | $ | 535 | | | $ | 13,545 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, 2022 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 739 | | | $ | 303 | | | $ | 630 | | | $ | — | | | $ | — | | | $ | 1,672 | | Natural gas revenues | | 84 | | | 44 | | | 300 | | | — | | | — | | | 428 | | Natural gas liquids revenues | | — | | | 5 | | | 197 | | | — | | | — | | | 202 | | Oil, natural gas, and natural gas liquids production revenues | | 823 | | | 352 | | | 1,127 | | | — | | | — | | | 2,302 | | Purchased oil and gas sales | | — | | | — | | | 585 | | | — | | | — | | | 585 | | | | | | | | | | | | | | | | | 823 | | | 352 | | | 1,712 | | | — | | | — | | | 2,887 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 119 | | | 107 | | | 138 | | | — | | | — | | | 364 | | Gathering, processing, and transmission | | 5 | | | 7 | | | 87 | | | — | | | — | | | 99 | | Purchased oil and gas costs | | — | | | — | | | 573 | | | — | | | — | | | 573 | | Taxes other than income | | — | | | — | | | 82 | | | — | | | — | | | 82 | | Exploration | | 29 | | | 1 | | | 16 | | | — | | | 49 | | | 95 | | Depreciation, depletion, and amortization | | 97 | | | 52 | | | 161 | | | — | | | — | | | 310 | | Asset retirement obligation accretion | | — | | | 21 | | | 8 | | | — | | | — | | | 29 | | | | | | | | | | | | | | | | | 250 | | | 188 | | | 1,065 | | | — | | | 49 | | | 1,552 | | Operating Income (Loss)(2) | | $ | 573 | | | $ | 164 | | | $ | 647 | | | $ | — | | | $ | (49) | | | 1,335 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | | | Derivative instrument losses, net | | | | | | | | | | | | (44) | | Gain on divestitures, net | | | | | | | | | | | | 31 | | Other, net | | | | | | | | | | | | (2) | | General and administrative | | | | | | | | | | | | (69) | | Transaction, reorganization, and separation | | | | | | | | | | | | (4) | | Financing costs, net | | | | | | | | | | | | (75) | | Income Before Income Taxes | | | | | | | | | | | | $ | 1,172 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2022 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 2,431 | | | $ | 938 | | | $ | 1,883 | | | $ | — | | | $ | — | | | $ | 5,252 | | Natural gas revenues | | 270 | | | 207 | | | 764 | | | — | | | — | | | 1,241 | | Natural gas liquids revenues | | 6 | | | 33 | | | 618 | | | — | | | (3) | | | 654 | | Oil, natural gas, and natural gas liquids production revenues | | 2,707 | | | 1,178 | | | 3,265 | | | — | | | (3) | | | 7,147 | | Purchased oil and gas sales | | — | | | — | | | 1,451 | | | 5 | | | — | | | 1,456 | | Midstream service affiliate revenues | | — | | | — | | | — | | | 16 | | | (16) | | | — | | | | 2,707 | | | 1,178 | | | 4,716 | | | 21 | | | (19) | | | 8,603 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 381 | | | 321 | | | 366 | | | — | | | (1) | | | 1,067 | | Gathering, processing, and transmission | | 15 | | | 31 | | | 241 | | | 5 | | | (18) | | | 274 | | Purchased oil and gas costs | | — | | | — | | | 1,452 | | | — | | | — | | | 1,452 | | Taxes other than income | | — | | | — | | | 227 | | | 3 | | | — | | | 230 | | Exploration | | 56 | | | 8 | | | 21 | | | — | | | 108 | | | 193 | | Depreciation, depletion, and amortization | | 285 | | | 168 | | | 424 | | | 2 | | | — | | | 879 | | Asset retirement obligation accretion | | — | | | 61 | | | 25 | | | 1 | | | — | | | 87 | | | | | | | | | | | | | | | | | 737 | | | 589 | | | 2,756 | | | 11 | | | 89 | | | 4,182 | | Operating Income (Loss)(2) | | $ | 1,970 | | | $ | 589 | | | $ | 1,960 | | | $ | 10 | | | $ | (108) | | | 4,421 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | Derivative instrument losses, net | | | | | | | | | | | | (138) | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 1,180 | | Other, net | | | | | | | | | | | | 107 | | General and administrative | | | | | | | | | | | | (314) | | Transaction, reorganization, and separation | | | | | | | | | | | | (21) | | Financing costs, net | | | | | | | | | | | | (303) | | Income Before Income Taxes | | | | | | | | | | | | $ | 4,932 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets(3) | | $ | 3,242 | | | $ | 2,185 | | | $ | 7,675 | | | $ | — | | | $ | 527 | | | $ | 13,629 | |
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Oil | | $ | 202 | | | $ | 227 | | | $ | 539 | | | $ | 779 | | Natural gas | | 23 | | | 26 | | | 73 | | | 87 | | Natural gas liquids | | — | | | — | | | — | | | 2 | |
(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022. (3)Intercompany balances are excluded from total assets. (4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.
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- DefinitionThe entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.
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v3.23.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
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9 Months Ended |
Sep. 30, 2023 |
Accounting Policies [Abstract] |
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Principles of Consolidation |
Principles of Consolidation The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary. On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail. The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik, which is considered a related party of the Company. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik.
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Use of Estimates |
Use of Estimates Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
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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).
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Revenue Recognition |
Revenue Recognition There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.6 billion and $1.3 billion as of September 30, 2023 and December 31, 2022, respectively. Payments under contracts with customers are typically due within a short-term period of 60 days after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC. Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. 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.
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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.
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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.
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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. Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.
|
Gathering, Processing, and Transmission (GPT) Facilities |
Gathering, Processing, and Transmission (GPT) Facilities GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields. 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.
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v3.23.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Schedule of Commodity Derivative Positions |
As of September 30, 2023, the Company had the following open natural gas financial basis swap contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Basis Swap Purchased | | Basis Swap Sold | Production Period | | Settlement Index | | MMBtu (in 000’s) | | Weighted Average Price Differential | | MMBtu (in 000’s) | | Weighted Average Price Differential | October—December 2023 | | NYMEX Henry Hub/IF Waha | | 18,400 | | | $(1.15) | | — | | | — | October—December 2023 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 18,400 | | | $(0.08) | January—June 2024 | | NYMEX Henry Hub/IF Waha | | 16,380 | | | $(1.15) | | — | | | — | January—June 2024 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 16,380 | | | $(0.10) |
|
Schedule of Derivative Assets Measured at Fair Value |
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using | | | | | | | | | Quoted Price in Active Markets (Level 1) | | Significant Other Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value | | Netting(1) | | Carrying Amount | | | | | | | | | | | | | | | | (In millions) | September 30, 2023 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | Liabilities: | | | | | | | | | | | | | Commodity derivative instruments | | — | | | 50 | | | — | | | 50 | | | — | | | 50 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.
|
Schedule of Derivative Liabilities Measured at Fair Value |
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements Using | | | | | | | | | Quoted Price in Active Markets (Level 1) | | Significant Other Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value | | Netting(1) | | Carrying Amount | | | | | | | | | | | | | | | | (In millions) | September 30, 2023 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2022 | | | | | | | | | | | | | Assets: | | | | | | | | | | | | | Commodity derivative instruments | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | Liabilities: | | | | | | | | | | | | | Commodity derivative instruments | | — | | | 50 | | | — | | | 50 | | | — | | | 50 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.
|
Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations |
The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Current Assets: Other current assets | | $ | 16 | | | $ | — | | Other Assets: Deferred charges and other | | — | | | 5 | | Total derivative assets | | $ | 16 | | | $ | 5 | | | | | | | Current Liabilities: Other current liabilities | | $ | — | | | $ | 50 | | | | | | | Total derivative liabilities | | $ | — | | | $ | 50 | |
Derivative Activity Recorded in the Statement of Consolidated Operations The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Realized: | | | | | | | | | Commodity derivative instruments | | $ | 19 | | | $ | (2) | | | $ | 43 | | | $ | (11) | | Foreign currency derivative instruments | | — | | | (6) | | | — | | | (8) | | Realized gains (losses), net | | 19 | | | (8) | | | 43 | | | (19) | | Unrealized: | | | | | | | | | Commodity derivative instruments | | (19) | | | (35) | | | 61 | | | (79) | | | | | | | | | | | Foreign currency derivative instruments | | — | | | (1) | | | — | | | (9) | | Preferred Units embedded derivative | | — | | | — | | | — | | | (31) | | Unrealized gains (losses), net | | (19) | | | (36) | | | 61 | | | (119) | | Derivative instrument gains (losses), net | | $ | — | | | $ | (44) | | | $ | 104 | | | $ | (138) | |
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v3.23.3
EQUITY METHOD INTERESTS (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Equity Method Investments and Joint Ventures [Abstract] |
|
Schedule of Equity Method Investment Information |
The following table represents sales and costs associated with Kinetik: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Natural gas and NGLs sales | | $ | 35 | | | $ | — | | | $ | 78 | | | $ | — | | Purchased oil and gas sales | | 11 | | | — | | | 18 | | | — | | | | $ | 46 | | | $ | — | | | $ | 96 | | | $ | — | | | | | | | | | | | Gathering, processing, and transmission costs | | $ | 26 | | | $ | 28 | | | $ | 81 | | | $ | 64 | | Purchased oil and gas costs | | 37 | | | — | | | 65 | | | — | | | | $ | 63 | | | $ | 28 | | | $ | 146 | | | $ | 64 | |
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v3.23.3
OTHER CURRENT LIABILITIES (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Payables and Accruals [Abstract] |
|
Schedule of Other Current Liabilities |
The following table provides detail of the Company’s other current liabilities: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Accrued operating expenses | | $ | 161 | | | $ | 145 | | Accrued exploration and development | | 328 | | | 333 | | Accrued compensation and benefits | | 379 | | | 514 | | Accrued interest | | 66 | | | 97 | | Accrued income taxes | | 228 | | | 90 | | Current asset retirement obligation | | 55 | | | 55 | | Current operating lease liability | | 108 | | | 167 | | | | | | | Current decommissioning contingency for sold Gulf of Mexico properties | | 225 | | | 450 | | Other | | 342 | | | 292 | | Total Other current liabilities | | $ | 1,892 | | | $ | 2,143 | |
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v3.23.3
ASSET RETIREMENT OBLIGATION (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Asset Retirement Obligation Disclosure [Abstract] |
|
Schedule of Asset Retirement Obligation |
The following table describes changes to the Company’s asset retirement obligation (ARO) liability: | | | | | | | | | | | September 30, 2023 | | | (In millions) | Asset retirement obligation, December 31, 2022 | | $ | 1,995 | | Liabilities incurred | | 14 | | | | | Liabilities settled | | (34) | | | | | | | | | | | Accretion expense | | 86 | | | | | Asset retirement obligation, September 30, 2023 | | 2,061 | | Less current portion | | (55) | | Asset retirement obligation, long-term | | $ | 2,006 | |
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v3.23.3
DEBT AND FINANCING COSTS (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Debt Disclosure [Abstract] |
|
Schedule of Debt |
The following table presents the carrying values of the Company’s debt: | | | | | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | | | | | | | | (In millions) | Apache notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 4,835 | | | $ | 4,908 | | | | | | | Syndicated credit facilities(2) | | 768 | | | 566 | | Apache finance lease obligations | | 33 | | | 34 | | Unamortized discount | | (26) | | | (27) | | Debt issuance costs | | (26) | | | (28) | | Total debt | | 5,584 | | | 5,453 | | Current maturities | | (2) | | | (2) | | Long-term debt | | $ | 5,582 | | | $ | 5,451 | |
(1) The fair values of the Apache notes and debentures were $4.1 billion and $4.2 billion as of September 30, 2023 and December 31, 2022, respectively. The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement). (2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.
|
Schedule of Financing Costs, Net |
The following table presents the components of the Company’s financing costs, net: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Interest expense | | $ | 89 | | | $ | 80 | | | $ | 266 | | | $ | 249 | | Amortization of debt issuance costs | | 1 | | | 1 | | | 3 | | | 8 | | Capitalized interest | | (7) | | | (5) | | | (18) | | | (13) | | (Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | | Interest income | | (2) | | | (1) | | | (7) | | | (8) | | Financing costs, net | | $ | 81 | | | $ | 75 | | | $ | 235 | | | $ | 303 | |
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v3.23.3
CAPITAL STOCK (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Equity [Abstract] |
|
Schedule Reconciliation of the Components of Basic and Diluted Net Income Per Common Share |
The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | | 2023 | | 2022 | | | Income | | Shares | | Per Share | | Income | | Shares | | Per Share | | | | | | | | | | | | | | | | (In millions, except per share amounts) | Basic: | | | | | | | | | | | | | Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 329 | | | $ | 1.28 | | Effect of Dilutive Securities: | | | | | | | | | | | | | Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | — | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income attributable to common stock | | $ | 459 | | | 308 | | | $ | 1.49 | | | $ | 422 | | | 330 | | | $ | 1.28 | | | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | | Income | | Shares | | Per Share | | Income | | Shares | | Per Share | | | | | | | | | | | | | | | | (In millions, except per share amounts) | Basic: | | | | | | | | | | | | | Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 339 | | | $ | 9.54 | | Effect of Dilutive Securities: | | | | | | | | | | | | | Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | 1 | | | $ | (0.03) | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income attributable to common stock | | $ | 1,082 | | | 309 | | | $ | 3.50 | | | $ | 3,231 | | | 340 | | | $ | 9.51 | |
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v3.23.3
BUSINESS SEGMENT INFORMATION (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Segment Reporting [Abstract] |
|
Schedule of Financial Segment Information |
Financial information for each segment is presented below: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total | | | Upstream | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, 2023 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 724 | | | $ | 348 | | | $ | 633 | | | $ | — | | | $ | — | | | $ | 1,705 | | Natural gas revenues | | 81 | | | 66 | | | 89 | | | — | | | — | | | 236 | | Natural gas liquids revenues | | — | | | 5 | | | 133 | | | — | | | — | | | 138 | | Oil, natural gas, and natural gas liquids production revenues | | 805 | | | 419 | | | 855 | | | — | | | — | | | 2,079 | | Purchased oil and gas sales | | — | | | — | | | 229 | | | — | | | — | | | 229 | | | | | | | | | | | | | | | | | 805 | | | 419 | | | 1,084 | | | — | | | — | | | 2,308 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 128 | | | 102 | | | 164 | | | — | | | — | | | 394 | | Gathering, processing, and transmission | | 13 | | | 15 | | | 61 | | | — | | | — | | | 89 | | Purchased oil and gas costs | | — | | | — | | | 211 | | | — | | | — | | | 211 | | Taxes other than income | | — | | | — | | | 61 | | | — | | | — | | | 61 | | Exploration | | 25 | | | 9 | | | 4 | | | — | | | 11 | | | 49 | | Depreciation, depletion, and amortization | | 129 | | | 90 | | | 199 | | | — | | | — | | | 418 | | Asset retirement obligation accretion | | — | | | 20 | | | 9 | | | — | | | — | | | 29 | | | | | | | | | | | | | | | | | 295 | | | 236 | | | 709 | | | — | | | 11 | | | 1,251 | | Operating Income (Loss)(2) | | $ | 510 | | | $ | 183 | | | $ | 375 | | | $ | — | | | $ | (11) | | | 1,057 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | General and administrative | | | | | | | | | | | | (139) | | Transaction, reorganization, and separation | | | | | | | | | | | | (5) | | Financing costs, net | | | | | | | | | | | | (81) | | Income Before Income Taxes | | | | | | | | | | | | $ | 833 | | | | | | | | | | | | | | |
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| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2023 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 1,971 | | | $ | 865 | | | $ | 1,631 | | | $ | — | | | $ | — | | | $ | 4,467 | | Natural gas revenues | | 264 | | | 165 | | | 229 | | | — | | | — | | | 658 | | Natural gas liquids revenues | | — | | | 19 | | | 356 | | | — | | | — | | | 375 | | Oil, natural gas, and natural gas liquids production revenues | | 2,235 | | | 1,049 | | | 2,216 | | | — | | | — | | | 5,500 | | Purchased oil and gas sales | | — | | | — | | | 612 | | | — | | | — | | | 612 | | | | | | | | | | | | | | | | | 2,235 | | | 1,049 | | | 2,828 | | | — | | | — | | | 6,112 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 346 | | | 278 | | | 452 | | | — | | | — | | | 1,076 | | Gathering, processing, and transmission | | 26 | | | 38 | | | 181 | | | — | | | — | | | 245 | | Purchased oil and gas costs | | — | | | — | | | 558 | | | — | | | — | | | 558 | | Taxes other than income | | — | | | — | | | 163 | | | — | | | — | | | 163 | | Exploration | | 91 | | | 18 | | | 10 | | | — | | | 25 | | | 144 | | Depreciation, depletion, and amortization | | 378 | | | 209 | | | 530 | | | — | | | — | | | 1,117 | | Asset retirement obligation accretion | | — | | | 57 | | | 29 | | | — | | | — | | | 86 | | Impairments | | — | | | 46 | | | — | | | — | | | — | | | 46 | | | | 841 | | | 646 | | | 1,923 | | | — | | | 25 | | | 3,435 | | Operating Income (Loss)(2) | | $ | 1,394 | | | $ | 403 | | | $ | 905 | | | $ | — | | | $ | (25) | | | 2,677 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | Derivative instrument gains, net | | | | | | | | | | | | 104 | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 7 | | Other, net | | | | | | | | | | | | 77 | | General and administrative | | | | | | | | | | | | (276) | | Transaction, reorganization, and separation | | | | | | | | | | | | (11) | | Financing costs, net | | | | | | | | | | | | (235) | | Income Before Income Taxes | | | | | | | | | | | | $ | 2,343 | | | | | | | | | | | | | | | Total Assets(3) | | $ | 3,518 | | | $ | 1,665 | | | $ | 7,827 | | | $ | — | | | $ | 535 | | | $ | 13,545 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, 2022 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 739 | | | $ | 303 | | | $ | 630 | | | $ | — | | | $ | — | | | $ | 1,672 | | Natural gas revenues | | 84 | | | 44 | | | 300 | | | — | | | — | | | 428 | | Natural gas liquids revenues | | — | | | 5 | | | 197 | | | — | | | — | | | 202 | | Oil, natural gas, and natural gas liquids production revenues | | 823 | | | 352 | | | 1,127 | | | — | | | — | | | 2,302 | | Purchased oil and gas sales | | — | | | — | | | 585 | | | — | | | — | | | 585 | | | | | | | | | | | | | | | | | 823 | | | 352 | | | 1,712 | | | — | | | — | | | 2,887 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 119 | | | 107 | | | 138 | | | — | | | — | | | 364 | | Gathering, processing, and transmission | | 5 | | | 7 | | | 87 | | | — | | | — | | | 99 | | Purchased oil and gas costs | | — | | | — | | | 573 | | | — | | | — | | | 573 | | Taxes other than income | | — | | | — | | | 82 | | | — | | | — | | | 82 | | Exploration | | 29 | | | 1 | | | 16 | | | — | | | 49 | | | 95 | | Depreciation, depletion, and amortization | | 97 | | | 52 | | | 161 | | | — | | | — | | | 310 | | Asset retirement obligation accretion | | — | | | 21 | | | 8 | | | — | | | — | | | 29 | | | | | | | | | | | | | | | | | 250 | | | 188 | | | 1,065 | | | — | | | 49 | | | 1,552 | | Operating Income (Loss)(2) | | $ | 573 | | | $ | 164 | | | $ | 647 | | | $ | — | | | $ | (49) | | | 1,335 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | | | Derivative instrument losses, net | | | | | | | | | | | | (44) | | Gain on divestitures, net | | | | | | | | | | | | 31 | | Other, net | | | | | | | | | | | | (2) | | General and administrative | | | | | | | | | | | | (69) | | Transaction, reorganization, and separation | | | | | | | | | | | | (4) | | Financing costs, net | | | | | | | | | | | | (75) | | Income Before Income Taxes | | | | | | | | | | | | $ | 1,172 | | | | | | | | | | | | | | |
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| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) | | | Upstream | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2022 | | (In millions) | Revenues: | | | | | | | | | | | | | Oil revenues | | $ | 2,431 | | | $ | 938 | | | $ | 1,883 | | | $ | — | | | $ | — | | | $ | 5,252 | | Natural gas revenues | | 270 | | | 207 | | | 764 | | | — | | | — | | | 1,241 | | Natural gas liquids revenues | | 6 | | | 33 | | | 618 | | | — | | | (3) | | | 654 | | Oil, natural gas, and natural gas liquids production revenues | | 2,707 | | | 1,178 | | | 3,265 | | | — | | | (3) | | | 7,147 | | Purchased oil and gas sales | | — | | | — | | | 1,451 | | | 5 | | | — | | | 1,456 | | Midstream service affiliate revenues | | — | | | — | | | — | | | 16 | | | (16) | | | — | | | | 2,707 | | | 1,178 | | | 4,716 | | | 21 | | | (19) | | | 8,603 | | Operating Expenses: | | | | | | | | | | | | | Lease operating expenses | | 381 | | | 321 | | | 366 | | | — | | | (1) | | | 1,067 | | Gathering, processing, and transmission | | 15 | | | 31 | | | 241 | | | 5 | | | (18) | | | 274 | | Purchased oil and gas costs | | — | | | — | | | 1,452 | | | — | | | — | | | 1,452 | | Taxes other than income | | — | | | — | | | 227 | | | 3 | | | — | | | 230 | | Exploration | | 56 | | | 8 | | | 21 | | | — | | | 108 | | | 193 | | Depreciation, depletion, and amortization | | 285 | | | 168 | | | 424 | | | 2 | | | — | | | 879 | | Asset retirement obligation accretion | | — | | | 61 | | | 25 | | | 1 | | | — | | | 87 | | | | | | | | | | | | | | | | | 737 | | | 589 | | | 2,756 | | | 11 | | | 89 | | | 4,182 | | Operating Income (Loss)(2) | | $ | 1,970 | | | $ | 589 | | | $ | 1,960 | | | $ | 10 | | | $ | (108) | | | 4,421 | | | | | | | | | | | | | | | Other Income (Expense): | | | | | | | | | | | | | Derivative instrument losses, net | | | | | | | | | | | | (138) | | | | | | | | | | | | | | | Gain on divestitures, net | | | | | | | | | | | | 1,180 | | Other, net | | | | | | | | | | | | 107 | | General and administrative | | | | | | | | | | | | (314) | | Transaction, reorganization, and separation | | | | | | | | | | | | (21) | | Financing costs, net | | | | | | | | | | | | (303) | | Income Before Income Taxes | | | | | | | | | | | | $ | 4,932 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total Assets(3) | | $ | 3,242 | | | $ | 2,185 | | | $ | 7,675 | | | $ | — | | | $ | 527 | | | $ | 13,629 | |
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters and nine months ended September 30, 2023 and 2022 of: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, | | | 2023 | | 2022 | | 2023 | | 2022 | | | | | | | | | | | | (In millions) | Oil | | $ | 202 | | | $ | 227 | | | $ | 539 | | | $ | 779 | | Natural gas | | 23 | | | 26 | | | 73 | | | 87 | | Natural gas liquids | | — | | | — | | | — | | | 2 | |
(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2 million, $6 million, and $1 million, respectively, for the third quarter of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022. (3)Intercompany balances are excluded from total assets. (4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.
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v3.23.3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)
|
3 Months Ended |
9 Months Ended |
|
Sep. 30, 2023 |
Jun. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Schedule Of Significant Accounting Policies [Line Items] |
|
|
|
|
|
|
Other asset impairments |
$ 0
|
|
$ 0
|
$ 0
|
$ 0
|
|
Receivables from contracts with customer, net |
$ 1,600,000,000
|
|
|
$ 1,600,000,000
|
|
$ 1,300,000,000
|
Inventory write-down |
|
$ 46,000,000
|
|
|
|
|
Kinetik |
|
|
|
|
|
|
Schedule Of Significant Accounting Policies [Line Items] |
|
|
|
|
|
|
Ownership percentage by noncontrolling owners |
10.00%
|
|
|
10.00%
|
|
|
Sinopec | Apache Egypt |
|
|
|
|
|
|
Schedule Of Significant Accounting Policies [Line Items] |
|
|
|
|
|
|
Ownership percentage by noncontrolling owners |
33.33%
|
|
|
33.33%
|
|
|
Third-Party Investors | ALTM |
|
|
|
|
|
|
Schedule Of Significant Accounting Policies [Line Items] |
|
|
|
|
|
|
Ownership percentage by noncontrolling owners |
21.00%
|
|
|
21.00%
|
|
|
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v3.23.3
ACQUISITIONS AND DIVESTITURES (Details) - USD ($) shares in Millions, $ in Millions |
|
1 Months Ended |
3 Months Ended |
9 Months Ended |
|
|
Feb. 22, 2022 |
Mar. 31, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Feb. 21, 2022 |
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Proceeds from sale of oil and gas properties |
|
|
|
|
$ 29
|
$ 778
|
|
|
Acquisition of delaware basin properties |
|
|
|
|
24
|
563
|
|
|
Deconsolidation gain |
$ 609
|
|
|
|
|
|
|
|
Deconsolidation, net amount of balance sheet |
193
|
|
|
|
|
|
|
|
Equity method interests |
|
|
$ 681
|
|
$ 681
|
|
$ 624
|
|
Kinetik |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Equity method interests |
$ 802
|
|
|
|
|
|
|
|
Shares sold (in shares) |
|
4
|
|
|
|
|
|
|
Proceeds from sale of stock |
|
$ 224
|
|
|
|
|
|
|
Loss on disposition of stock |
|
$ 25
|
|
|
|
|
|
|
Kinetik |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Ownership percentage by noncontrolling owners |
|
|
10.00%
|
|
10.00%
|
|
|
|
Apache Midstream LLC | ALTM |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Ownership percentage by parent |
|
|
|
|
|
|
|
79.00%
|
BCP Business Combination | ALTM | ALTM |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Ownership percentage by noncontrolling owners |
20.00%
|
|
|
|
|
|
|
|
BCP Business Combination | ALTM | Class C Common Stock |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Business acquisition, equity interest issued or issuable, number of shares (in shares) |
50
|
|
|
|
|
|
|
|
BCP Business Combination | BCP Business Combination Contributor | Kinetik |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Ownership percentage by parent |
75.00%
|
|
|
|
|
|
|
|
Non-Core Assets And Leasehold | Disposed of by Sale |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Proceeds from sale of oil and gas properties |
|
|
$ 1
|
$ 37
|
$ 29
|
52
|
|
|
Gain on sale of non-core assets |
|
|
1
|
34
|
7
|
36
|
|
|
Non-Core Mineral Rights | Disposed of by Sale |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Proceeds from sale of oil and gas properties |
|
|
|
|
|
726
|
|
|
Gain on sale of non-core assets |
|
|
|
|
|
560
|
|
|
Permian Basin |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Oil and gas property acquisitions consideration payment |
|
|
$ 1
|
|
$ 11
|
|
|
|
Payments to acquire leasehold and property |
|
|
|
3
|
|
30
|
|
|
Delaware Basin |
|
|
|
|
|
|
|
|
Business Acquisition [Line Items] |
|
|
|
|
|
|
|
|
Oil and gas property acquisitions consideration payment |
|
|
|
615
|
|
|
|
|
Asset acquisition, proved properties amount |
|
|
|
581
|
|
581
|
|
|
Asset acquisition, unproved leasehold amount |
|
|
|
38
|
|
38
|
|
|
Asset acquisition, abandonment obligations |
|
|
|
$ 4
|
|
$ 4
|
|
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v3.23.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions |
Sep. 30, 2023 |
Dec. 31, 2022 |
Assets: |
|
|
Derivative asset |
$ 16
|
$ 5
|
Liabilities: |
|
|
Derivative liability |
0
|
50
|
Commodity derivative instruments |
|
|
Assets: |
|
|
Derivative asset, fair value |
16
|
5
|
Derivative asset, netting |
0
|
0
|
Derivative asset |
16
|
5
|
Liabilities: |
|
|
Derivative liability, fair value |
|
50
|
Derivative liability, netting |
|
0
|
Derivative liability |
|
50
|
Quoted Price in Active Markets (Level 1) | Commodity derivative instruments |
|
|
Assets: |
|
|
Derivative asset, fair value |
0
|
0
|
Liabilities: |
|
|
Derivative liability, fair value |
|
0
|
Significant Other Inputs (Level 2) | Commodity derivative instruments |
|
|
Assets: |
|
|
Derivative asset, fair value |
16
|
5
|
Liabilities: |
|
|
Derivative liability, fair value |
|
50
|
Significant Unobservable Inputs (Level 3) | Commodity derivative instruments |
|
|
Assets: |
|
|
Derivative asset, fair value |
$ 0
|
0
|
Liabilities: |
|
|
Derivative liability, fair value |
|
$ 0
|
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v3.23.3
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Derivative Instruments, Gain (Loss) [Line Items] |
|
|
|
|
Unrealized gains (losses), net |
|
|
$ 61
|
$ (119)
|
Derivative instrument gains (losses), net |
$ 0
|
$ (44)
|
104
|
(138)
|
Not Designated as Hedging Instrument |
|
|
|
|
Derivative Instruments, Gain (Loss) [Line Items] |
|
|
|
|
Realized gains (losses), net |
19
|
(8)
|
43
|
(19)
|
Unrealized gains (losses), net |
(19)
|
(36)
|
61
|
(119)
|
Derivative instrument gains (losses), net |
0
|
(44)
|
104
|
(138)
|
Commodity derivative instruments | Not Designated as Hedging Instrument |
|
|
|
|
Derivative Instruments, Gain (Loss) [Line Items] |
|
|
|
|
Realized gains (losses), net |
19
|
(2)
|
43
|
(11)
|
Unrealized gains (losses), net |
(19)
|
(35)
|
61
|
(79)
|
Foreign currency derivative instruments | Not Designated as Hedging Instrument |
|
|
|
|
Derivative Instruments, Gain (Loss) [Line Items] |
|
|
|
|
Realized gains (losses), net |
0
|
(6)
|
0
|
(8)
|
Unrealized gains (losses), net |
0
|
(1)
|
0
|
(9)
|
Preferred Units embedded derivative | Not Designated as Hedging Instrument |
|
|
|
|
Derivative Instruments, Gain (Loss) [Line Items] |
|
|
|
|
Unrealized gains (losses), net |
$ 0
|
$ 0
|
$ 0
|
$ (31)
|
X |
- DefinitionAmount of increase (decrease) in the fair value of derivatives recognized in the income statement.
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v3.23.3
EQUITY METHOD INTERESTS - Narrative (Details) shares in Millions, $ in Millions |
1 Months Ended |
3 Months Ended |
9 Months Ended |
|
|
Mar. 31, 2022
USD ($)
shares
|
Sep. 30, 2023
USD ($)
shares
|
Sep. 30, 2022
USD ($)
|
Jun. 30, 2022
shares
|
Sep. 30, 2023
USD ($)
shares
|
Sep. 30, 2022
USD ($)
|
Dec. 31, 2022
USD ($)
|
Feb. 22, 2022
shares
|
Schedule of Equity Method Investments [Line Items] |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ 741
|
|
|
$ 741
|
|
$ 771
|
|
Receivables |
|
$ 1,753
|
|
|
$ 1,753
|
|
$ 1,466
|
|
Kinetik |
|
|
|
|
|
|
|
|
Schedule of Equity Method Investments [Line Items] |
|
|
|
|
|
|
|
|
Equity method investment, number of shares (in shares) | shares |
|
20.2
|
|
17.7
|
20.2
|
|
|
12.9
|
Shares sold (in shares) | shares |
4.0
|
|
|
|
|
|
|
|
Loss on sale of stock |
$ 25
|
|
|
|
|
|
|
|
Dividends paid-in-kind (in shares) | shares |
|
|
|
|
2.5
|
|
|
|
Interest percentage |
|
14.00%
|
|
|
14.00%
|
|
|
|
Gains (losses) on changes in fair value of equity method interest |
|
$ (14)
|
$ (17)
|
|
$ 57
|
$ 49
|
|
|
Accounts payable |
|
43
|
|
|
43
|
|
|
|
Receivables |
|
$ 29
|
|
|
$ 29
|
|
|
|
Kinetik | Kinetik |
|
|
|
|
|
|
|
|
Schedule of Equity Method Investments [Line Items] |
|
|
|
|
|
|
|
|
Stock split conversion ratio |
|
|
|
2
|
|
|
|
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v3.23.3
ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Millions |
3 Months Ended |
9 Months Ended |
|
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] |
|
|
|
|
|
Asset retirement obligation at the beginning of period |
|
|
$ 1,995
|
|
|
Liabilities incurred |
|
|
14
|
|
|
Liabilities settled |
|
|
(34)
|
|
|
Accretion expense |
$ 29
|
$ 29
|
86
|
$ 87
|
|
Asset retirement obligation at the end of period |
2,061
|
|
2,061
|
|
|
Less current portion |
(55)
|
|
(55)
|
|
$ (55)
|
Asset retirement obligation, long-term |
$ 2,006
|
|
$ 2,006
|
|
$ 1,940
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v3.23.3
DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions |
Sep. 30, 2023 |
Dec. 31, 2022 |
Debt Instrument [Line Items] |
|
|
Apache finance lease obligations |
$ 33
|
$ 34
|
Unamortized discount |
(26)
|
(27)
|
Debt issuance costs |
(26)
|
(28)
|
Total debt |
5,584
|
5,453
|
Current maturities |
(2)
|
(2)
|
Long-term debt |
5,582
|
5,451
|
Apache notes and debentures | Unsecured Debt |
|
|
Debt Instrument [Line Items] |
|
|
Apache notes and debentures before unamortized discount and debt issuance costs |
4,835
|
4,908
|
Debt instrument, fair value |
4,100
|
4,200
|
Syndicated credit facility | Line of Credit | Revolving Credit Facility |
|
|
Debt Instrument [Line Items] |
|
|
Syndicated credit facilities |
$ 768
|
$ 566
|
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v3.23.3
DEBT AND FINANCING COSTS - Additional Information (Details) £ in Millions |
|
|
3 Months Ended |
9 Months Ended |
|
|
|
Apr. 29, 2022
USD ($)
credit_agreement
option
|
Jan. 18, 2022
USD ($)
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Mar. 31, 2022
USD ($)
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Sep. 30, 2023
GBP (£)
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2022
GBP (£)
|
Apr. 29, 2022
GBP (£)
credit_agreement
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Finance lease obligations, current |
|
|
$ 2,000,000
|
|
|
$ 2,000,000
|
|
|
$ 2,000,000
|
|
|
Gain (loss) on extinguishment of debt |
|
|
0
|
$ 0
|
|
9,000,000
|
$ (67,000,000)
|
|
|
|
|
Number of syndicated credit agreements | credit_agreement |
2
|
|
|
|
|
|
|
|
|
|
2
|
USD Agreement | Line of Credit |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Debt instrument term |
5 years
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, committed amount |
$ 1,800,000,000
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, increased committed amount |
$ 2,300,000,000
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, number of extension options | option |
2
|
|
|
|
|
|
|
|
|
|
|
Debt extension term |
1 year
|
|
|
|
|
|
|
|
|
|
|
USD Agreement | Line of Credit | Letter of Credit |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Credit facility maximum borrowing capacity |
$ 750,000,000
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, current borrowing capacity |
150,000,000
|
|
|
|
|
|
|
|
|
|
|
Principal amount outstanding |
$ 300,000,000
|
|
|
|
|
|
|
|
|
|
|
Letters of credit outstanding, amount |
|
|
0
|
|
|
0
|
|
|
20,000,000
|
|
|
GBP Agreement | Line of Credit |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Debt instrument term |
5 years
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, committed amount | £ |
|
|
|
|
|
|
|
|
|
|
£ 1,500
|
Line of credit facility, number of extension options | option |
2
|
|
|
|
|
|
|
|
|
|
|
Debt extension term |
1 year
|
|
|
|
|
|
|
|
|
|
|
GBP Agreement | Line of Credit | Letter of Credit |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Letters of credit outstanding, amount | £ |
|
|
|
|
|
|
|
£ 572
|
|
£ 652
|
|
Former Facility | Revolving Credit Facility |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, terminated Amount |
$ 4,000,000,000
|
|
|
|
|
|
|
|
|
|
|
Line of credit facility, covenant benchmark amount |
$ 1,000,000,000
|
|
|
|
|
|
|
|
|
|
|
Syndicated credit facility | Line of Credit | Revolving Credit Facility |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Credit facility |
|
|
768,000,000
|
|
|
768,000,000
|
|
|
566,000,000
|
|
|
Apache credit facility |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Letters of credit outstanding, amount |
|
|
3,000,000
|
|
|
3,000,000
|
|
£ 185
|
$ 17,000,000
|
£ 199
|
|
Uncommitted Lines Of Credit | Line of Credit |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Credit facility |
|
|
0
|
|
|
0
|
|
|
|
|
|
Senior Notes | 3.25% notes due 2022 |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Current maturities |
|
$ 213,000,000
|
|
|
|
|
|
|
|
|
|
Debt interest rate |
|
3.25%
|
|
|
|
|
|
|
|
|
|
Redemption price, percentage of principal amount redeemed |
|
100.00%
|
|
|
|
|
|
|
|
|
|
Senior Notes | Open Market Repurchase |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Debt repurchased principal amount |
|
|
74,000,000
|
15,000,000
|
|
74,000,000
|
15,000,000
|
|
|
|
|
Debt instrument repurchase program |
|
|
$ 65,000,000
|
16,000,000
|
|
65,000,000
|
16,000,000
|
|
|
|
|
Premium (discount) to par of debt repurchase |
|
|
|
|
$ 1,000,000
|
(10,000,000)
|
|
|
|
|
|
Gain (loss) on extinguishment of debt |
|
|
|
|
$ (1,000,000)
|
$ 9,000,000
|
|
|
|
|
|
Senior Notes | Cash Tender Offers |
|
|
|
|
|
|
|
|
|
|
|
Debt Instrument [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
Debt repurchased principal amount |
|
|
|
1,100,000,000
|
|
|
1,100,000,000
|
|
|
|
|
Debt instrument repurchase program |
|
|
|
1,200,000,000
|
|
|
1,200,000,000
|
|
|
|
|
Gain (loss) on extinguishment of debt |
|
|
|
|
|
|
(66,000,000)
|
|
|
|
|
Debt instrument, unamortized discount and issuance costs |
|
|
|
$ 11,000,000
|
|
|
$ 11,000,000
|
|
|
|
|
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v3.23.3
COMMITMENTS AND CONTINGENCIES (Details) $ in Millions |
|
|
|
|
|
|
9 Months Ended |
12 Months Ended |
|
|
|
|
|
|
Sep. 10, 2020
defendant
|
Sep. 11, 2019
USD ($)
plaintiff
|
Dec. 20, 2017
action
|
Jul. 17, 2017
defendant
action
|
Mar. 21, 2016
USD ($)
|
Mar. 20, 2016
USD ($)
|
Sep. 30, 2023
USD ($)
bond
letter_of_credit
|
Dec. 31, 2013
USD ($)
profit_interest
|
Jun. 21, 2023
surety
|
Dec. 31, 2022
USD ($)
|
Apr. 05, 2022
letter
|
Dec. 31, 2017
AUD ($)
|
Apr. 30, 2017
AUD ($)
|
Mar. 12, 2014
USD ($)
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued liability for legal contingencies |
|
|
|
|
|
|
$ 49,000,000
|
|
|
|
|
|
|
|
Environmental tax and royalty obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ 100,000,000
|
Retain right of obligations |
|
|
|
|
|
|
45,000,000
|
|
|
|
|
|
|
|
Undiscounted reserve for environmental remediation |
|
|
|
|
|
|
5,000,000
|
|
|
|
|
|
|
|
Number of prior letters notifying unable to fund decommissioning obligations | letter |
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
Decommissioning costs incurred |
|
|
|
|
|
|
692,000,000
|
|
|
|
|
|
|
|
Decommissioning costs reimbursed amount from trust |
|
|
|
|
|
|
288,000,000
|
|
|
|
|
|
|
|
Decommissioning costs reimbursed amount from the letters of credit |
|
|
|
|
|
|
87,000,000
|
|
|
|
|
|
|
|
Standby loan agreed to provide related to ARO (up to) |
|
|
|
|
|
|
400,000,000
|
|
|
|
|
|
|
|
Decommissioning contingency for sold |
|
|
|
|
|
|
695,000,000
|
|
|
|
|
|
|
|
Decommissioning contingency for sold properties |
|
|
|
|
|
|
470,000,000
|
|
|
$ 738,000,000
|
|
|
|
|
Current decommissioning contingency for sold Gulf of Mexico properties |
|
|
|
|
|
|
225,000,000
|
|
|
450,000,000
|
|
|
|
|
Decommissioning security for sold properties |
|
|
|
|
|
|
411,000,000
|
|
|
|
|
|
|
|
Trust account for disposal group, number of net profits interests |
|
|
|
|
|
|
38,000,000
|
|
|
217,000,000
|
|
|
|
|
Current decommissioning security for sold Gulf of Mexico assets |
|
|
|
|
|
|
$ 373,000,000
|
|
|
$ 450,000,000
|
|
|
|
|
Sureties issued bonds directly | surety |
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Sureties issued bonds to issuing bank | surety |
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Gulf Of Mexico Shelf Operations and Properties | Disposed of by Sale |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of operations and properties |
|
|
|
|
|
|
|
$ 3,750,000,000
|
|
|
|
|
|
|
Trust account for disposal group, number of net profits interests | profit_interest |
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
Number of bond held | bond |
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
Number of debt instrument held | letter_of_credit |
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
Minimum |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AROs, estimated liability |
|
|
|
|
|
|
$ 695,000,000
|
|
|
|
|
|
|
|
Maximum |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AROs, estimated liability |
|
|
|
|
|
|
895,000,000
|
|
|
|
|
|
|
|
Apollo Exploration Lawsuit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plaintiffs alleged damages |
|
|
|
|
$ 200,000,000
|
|
|
|
|
|
|
|
|
|
Apollo Exploration Lawsuit | Minimum |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plaintiffs alleged damages |
|
|
|
|
|
$ 1,100,000,000
|
|
|
|
|
|
|
|
|
Australian Operations Divestiture Dispute | Apache Australia Operation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain contingency, unrecorded amount |
|
|
|
|
|
|
|
|
|
|
|
|
$ 80
|
|
Loss contingency, estimated of possible loss amount |
|
|
|
|
|
|
|
|
|
|
|
$ 200
|
|
|
Canadian Operations Divestiture Dispute |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plaintiffs alleged damages |
|
$ 60,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of plaintiffs | plaintiff |
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
Litigation settlement, amount to resolve all claims |
|
|
|
|
|
|
$ 7,000,000
|
|
|
|
|
|
|
|
California Litigation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of actions filed | action |
|
|
2
|
3
|
|
|
|
|
|
|
|
|
|
|
Number of defendants | defendant |
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
Delaware Litigation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitment And Contingencies [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of defendants | defendant |
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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v3.23.3
CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Basic: |
|
|
|
|
Income attributable to common stock |
$ 459
|
$ 422
|
$ 1,082
|
$ 3,231
|
Income attributable to common stock (in shares) |
308
|
329
|
309
|
339
|
Income attributable to common stock (in USD per share) |
$ 1.49
|
$ 1.28
|
$ 3.50
|
$ 9.54
|
Diluted: |
|
|
|
|
Income attributable to common stock |
$ 459
|
$ 422
|
$ 1,082
|
$ 3,231
|
Income attributable to common stock (in shares) |
308
|
330
|
309
|
340
|
Income attributable to common stock (in USD per share) |
$ 1.49
|
$ 1.28
|
$ 3.50
|
$ 9.51
|
Stock options and other |
|
|
|
|
Effect of Dilutive Securities: |
|
|
|
|
Stock options and other |
$ 0
|
$ 0
|
$ 0
|
$ 0
|
Stock options and other, shares (in shares) |
0
|
1
|
0
|
1
|
Stock options and other, per share (in USD per share) |
$ 0
|
$ 0
|
$ 0
|
$ (0.03)
|
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v3.23.3
CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions |
1 Months Ended |
3 Months Ended |
9 Months Ended |
|
Oct. 31, 2023 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Jun. 30, 2022 |
Dec. 31, 2021 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2018 |
Class of Stock [Line Items] |
|
|
|
|
|
|
|
|
Options and restricted stock, anti-dilutive (in shares) |
|
1,700,000
|
2,100,000
|
|
|
2,000,000
|
2,500,000
|
|
Number of shares authorized to be repurchased (in shares) |
|
|
|
|
|
|
|
40,000,000
|
Additional number of shares authorized to be repurchased (in shares) |
|
|
40,000,000
|
|
40,000,000
|
|
|
|
Treasury shares acquired (in shares) |
|
500,000
|
9,800,000
|
|
|
5,500,000
|
24,000,000
|
|
Treasure stock acquired, average price (in USD per share) |
|
$ 41.90
|
$ 33.86
|
|
|
$ 37.91
|
$ 36.78
|
|
Remaining authorized repurchase amount (in shares) |
|
47,100,000
|
|
|
|
47,100,000
|
|
|
Payments of dividend on common stock |
|
$ 77
|
$ 41
|
|
|
$ 232
|
$ 127
|
|
Common stock, dividends, per share (in USD per share) |
|
$ 0.25
|
$ 0.25
|
$ 0.125
|
|
$ 0.75
|
$ 0.50
|
|
Subsequent Event |
|
|
|
|
|
|
|
|
Class of Stock [Line Items] |
|
|
|
|
|
|
|
|
Treasury shares acquired (in shares) |
400,000
|
|
|
|
|
|
|
|
Treasure stock acquired, average price (in USD per share) |
$ 40.26
|
|
|
|
|
|
|
|
Remaining authorized repurchase amount (in shares) |
46,700,000
|
|
|
|
|
|
|
|
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- DefinitionStock Repurchase Program, Additional Number Of Shares Authorized To Be Repurchased
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- DefinitionNumber of operating segments. An operating segment is a component of an enterprise: (a) that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other components of the same enterprise), (b) whose operating results are regularly reviewed by the enterprise's chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance, and (c) for which discrete financial information is available. An operating segment may engage in business activities for which it has yet to earn revenues, for example, start-up operations may be operating segments before earning revenues.
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v3.23.3
BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions |
3 Months Ended |
9 Months Ended |
|
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
$ 394
|
$ 364
|
$ 1,076
|
$ 1,067
|
|
Taxes other than income |
|
61
|
82
|
163
|
230
|
|
Exploration |
|
49
|
95
|
144
|
193
|
|
Depreciation, depletion, and amortization |
|
418
|
310
|
1,117
|
879
|
|
Asset retirement obligation accretion |
|
29
|
29
|
86
|
87
|
|
Impairments |
|
0
|
0
|
46
|
0
|
|
Total operating expenses |
|
1,251
|
1,552
|
3,435
|
4,182
|
|
Operating Income (Loss) |
|
1,057
|
1,335
|
2,677
|
4,421
|
|
Other Income (Expense): |
|
|
|
|
|
|
Derivative instrument gains (losses), net |
|
0
|
(44)
|
104
|
(138)
|
|
Gain on divestitures, net |
|
1
|
31
|
7
|
1,180
|
|
Other, net |
|
|
(2)
|
77
|
107
|
|
General and administrative |
|
(139)
|
(69)
|
(276)
|
(314)
|
|
Transaction, reorganization, and separation |
|
(5)
|
(4)
|
(11)
|
(21)
|
|
Financing costs, net |
|
(81)
|
(75)
|
(235)
|
(303)
|
|
NET INCOME BEFORE INCOME TAXES |
|
833
|
1,172
|
2,343
|
4,932
|
|
Total assets |
|
13,545
|
13,629
|
13,545
|
13,629
|
$ 13,147
|
Operating Segments | Egypt |
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
128
|
119
|
346
|
381
|
|
Taxes other than income |
|
0
|
0
|
0
|
0
|
|
Exploration |
|
25
|
29
|
91
|
56
|
|
Depreciation, depletion, and amortization |
|
129
|
97
|
378
|
285
|
|
Asset retirement obligation accretion |
|
0
|
0
|
0
|
0
|
|
Impairments |
|
|
|
0
|
|
|
Total operating expenses |
|
295
|
250
|
841
|
737
|
|
Operating Income (Loss) |
|
510
|
573
|
1,394
|
1,970
|
|
Other Income (Expense): |
|
|
|
|
|
|
Total assets |
|
3,518
|
3,242
|
3,518
|
3,242
|
|
Impairments |
|
|
1
|
|
3
|
|
Operating Segments | North Sea |
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
102
|
107
|
278
|
321
|
|
Taxes other than income |
|
0
|
0
|
0
|
0
|
|
Exploration |
|
9
|
1
|
18
|
8
|
|
Depreciation, depletion, and amortization |
|
90
|
52
|
209
|
168
|
|
Asset retirement obligation accretion |
|
20
|
21
|
57
|
61
|
|
Impairments |
|
|
|
46
|
|
|
Total operating expenses |
|
236
|
188
|
646
|
589
|
|
Operating Income (Loss) |
|
183
|
164
|
403
|
589
|
|
Other Income (Expense): |
|
|
|
|
|
|
Total assets |
|
1,665
|
2,185
|
1,665
|
2,185
|
|
Impairments |
|
6
|
|
12
|
|
|
Operating Segments | U.S. |
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
164
|
138
|
452
|
366
|
|
Taxes other than income |
|
61
|
82
|
163
|
227
|
|
Exploration |
|
4
|
16
|
10
|
21
|
|
Depreciation, depletion, and amortization |
|
199
|
161
|
530
|
424
|
|
Asset retirement obligation accretion |
|
9
|
8
|
29
|
25
|
|
Impairments |
|
|
|
0
|
|
|
Total operating expenses |
|
709
|
1,065
|
1,923
|
2,756
|
|
Operating Income (Loss) |
|
375
|
647
|
905
|
1,960
|
|
Other Income (Expense): |
|
|
|
|
|
|
Total assets |
|
7,827
|
7,675
|
7,827
|
7,675
|
|
Impairments |
|
2
|
15
|
7
|
19
|
|
Operating Segments | Suriname |
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
Impairments |
|
1
|
|
1
|
|
|
Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
|
|
|
16
|
|
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
0
|
0
|
0
|
0
|
|
Taxes other than income |
|
0
|
0
|
0
|
3
|
|
Exploration |
|
0
|
0
|
0
|
0
|
|
Depreciation, depletion, and amortization |
|
0
|
0
|
0
|
2
|
|
Asset retirement obligation accretion |
|
0
|
0
|
0
|
1
|
|
Impairments |
|
|
|
0
|
|
|
Total operating expenses |
|
0
|
0
|
0
|
11
|
|
Operating Income (Loss) |
|
0
|
0
|
0
|
10
|
|
Other Income (Expense): |
|
|
|
|
|
|
Total assets |
|
0
|
0
|
0
|
0
|
|
Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
|
|
|
(16)
|
|
Operating Expenses: |
|
|
|
|
|
|
Lease operating expenses |
|
0
|
0
|
0
|
(1)
|
|
Taxes other than income |
|
0
|
0
|
0
|
0
|
|
Exploration |
|
11
|
49
|
25
|
108
|
|
Depreciation, depletion, and amortization |
|
0
|
0
|
0
|
0
|
|
Asset retirement obligation accretion |
|
0
|
0
|
0
|
0
|
|
Impairments |
|
|
|
0
|
|
|
Total operating expenses |
|
11
|
49
|
25
|
89
|
|
Operating Income (Loss) |
|
(11)
|
(49)
|
(25)
|
(108)
|
|
Other Income (Expense): |
|
|
|
|
|
|
Total assets |
|
535
|
527
|
535
|
527
|
|
Gathering, processing, and transmission costs |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
[1] |
2,079
|
2,302
|
5,500
|
7,147
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
[1] |
89
|
99
|
245
|
274
|
|
Gathering, processing, and transmission costs | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
805
|
823
|
2,235
|
2,707
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
13
|
5
|
26
|
15
|
|
Gathering, processing, and transmission costs | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
419
|
352
|
1,049
|
1,178
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
15
|
7
|
38
|
31
|
|
Gathering, processing, and transmission costs | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
855
|
1,127
|
2,216
|
3,265
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
61
|
87
|
181
|
241
|
|
Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
5
|
|
Gathering, processing, and transmission costs | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
(3)
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
(18)
|
|
Purchased oil and gas sales |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
[1] |
229
|
585
|
612
|
1,456
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
[1] |
211
|
573
|
558
|
1,452
|
|
Purchased oil and gas sales | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
0
|
0
|
0
|
0
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
0
|
|
Purchased oil and gas sales | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
0
|
0
|
0
|
0
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
0
|
|
Purchased oil and gas sales | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
229
|
585
|
612
|
1,451
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
211
|
573
|
558
|
1,452
|
|
Purchased oil and gas sales | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
0
|
0
|
0
|
5
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
0
|
|
Purchased oil and gas sales | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Purchased oil and gas sales |
|
0
|
0
|
0
|
0
|
|
Operating Expenses: |
|
|
|
|
|
|
Gathering, processing, and transmission & purchased oil and gas costs |
|
0
|
0
|
0
|
0
|
|
Oil and gas |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
2,308
|
2,887
|
6,112
|
8,603
|
|
Oil and gas | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
805
|
823
|
2,235
|
2,707
|
|
Oil and gas | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
419
|
352
|
1,049
|
1,178
|
|
Oil and gas | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
1,084
|
1,712
|
2,828
|
4,716
|
|
Oil and gas | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
0
|
0
|
0
|
21
|
|
Oil and gas | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Revenues |
|
0
|
0
|
0
|
(19)
|
|
Oil revenues |
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
Revenue from non-customers |
|
202
|
227
|
539
|
779
|
|
Oil revenues | Gathering, processing, and transmission costs |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
1,705
|
1,672
|
4,467
|
5,252
|
|
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
724
|
739
|
1,971
|
2,431
|
|
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
348
|
303
|
865
|
938
|
|
Oil revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
633
|
630
|
1,631
|
1,883
|
|
Oil revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Oil revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Natural gas revenues |
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
Revenue from non-customers |
|
23
|
26
|
73
|
87
|
|
Natural gas revenues | Gathering, processing, and transmission costs |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
236
|
428
|
658
|
1,241
|
|
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
81
|
84
|
264
|
270
|
|
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
66
|
44
|
165
|
207
|
|
Natural gas revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
89
|
300
|
229
|
764
|
|
Natural gas revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Natural gas revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Natural gas liquids revenues |
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
Revenue from non-customers |
|
0
|
0
|
0
|
2
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
138
|
202
|
375
|
654
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | Egypt |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
6
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | North Sea |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
5
|
5
|
19
|
33
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs | Operating Segments | U.S. |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
133
|
197
|
356
|
618
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs | Reportable Legal Entities | Altus Midstream |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
0
|
0
|
0
|
0
|
|
Natural gas liquids revenues | Gathering, processing, and transmission costs | Intersegment Eliminations & Other |
|
|
|
|
|
|
Segment Reporting Information [Line Items] |
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids production revenues |
|
$ 0
|
$ 0
|
$ 0
|
$ (3)
|
|
|
|
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