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 March 31, 2021June 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)
| | | | | |
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:
| | | | | | | | | | | | | | |
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.
| | | | | | | | | | | | | | | | | | | | |
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 ☒
| | | | | |
Number of shares of registrant’s common stock outstanding as of April 30, 2021July 31, 2023 | 377,972,835307,265,404 | |
TABLE OF CONTENTS
| Item | Item | | Page | Item | | Page |
| | | PART I - FINANCIAL INFORMATION | | | PART I - FINANCIAL INFORMATION | |
1. | 1. | | | | 1. | | | |
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2. | 2. | | | | 2. | | | |
3. | 3. | | | | 3. | | | |
4. | 4. | | | | 4. | | | |
| | | PART II - OTHER INFORMATION | | | PART II - OTHER INFORMATION | |
1. | 1. | | | | 1. | | | |
1A. | 1A. | | | | 1A. | | | |
2. | 2. | | | | 2. | | | |
| 6. | 6. | | | | 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, 2020,2022, 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:
•the scope, duration,changes in local, regional, national, and reoccurrenceinternational economic conditions, including as a result of any epidemics or pandemics, (including, specifically,such as the coronavirus disease 2019 (COVID-19) pandemic)pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;
•the availability and effectiveness of vaccine programs and therapeuticsany related to the treatment of COVID-19;variants;
•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;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;conditions, including market and macro-economic disruptions resulting from the Russian war in Ukraine and from 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 Company’s expectations with respect tobenefits derived from the new operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements set forthcontained in Part I, Item 1—Financial Statements of this Quarterlythe Company’s Annual Report on Form 10-Q) and10-K for the associated disclosure implications;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 of Apache Corporation, the Company’s predecessor registrant, for the fiscal year ended December 31, 2020;2022;
•other risks and uncertainties disclosed in the Company’s first-quarter 2021second-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 thethese 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 natural gas liquidsNGLs per day.
“bbl” or “bbls” means barrel or barrels of oil or natural gas liquids.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 natural gas liquids.NGLs.
“LNG” means liquefied natural gas.
“Mb/d” means Mbbls per day.
“Mbbls” means thousand barrels of oil or natural gas liquids.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 natural gas liquids.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 ourthe Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by ourthe 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-ownedwholly 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 June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | 2023 | | 2022 | | 2023 | | 2022 |
| | 2021 | | 2020 | | | | | | | | | |
| | | (In millions, except share data) | | | (In millions, except share data) |
REVENUES AND OTHER: | REVENUES AND OTHER: | | | REVENUES AND OTHER: | |
Oil, natural gas, and natural gas liquids production revenues | | $ | 1,431 | | | $ | 1,236 | | | |
Purchased oil and gas sales | | 440 | | | 108 | | | |
Oil, natural gas, and natural gas liquids production revenues(1) | | Oil, natural gas, and natural gas liquids production revenues(1) | | $ | 1,652 | | | $ | 2,525 | | | $ | 3,421 | | | $ | 4,845 | |
Purchased oil and gas sales(1) | | Purchased oil and gas sales(1) | | 144 | | | 522 | | | 383 | | | 871 | |
Total revenues | Total revenues | | 1,871 | | | 1,344 | | | Total revenues | | 1,796 | | | 3,047 | | | 3,804 | | | 5,716 | |
Derivative instrument gains (losses), net | Derivative instrument gains (losses), net | | 158 | | | (103) | | | Derivative instrument gains (losses), net | | 51 | | | (32) | | | 104 | | | (94) | |
Gain on divestitures, net | | 2 | | | 25 | | | |
Gain (loss) on divestitures, net | | Gain (loss) on divestitures, net | | 5 | | | (27) | | | 6 | | | 1,149 | |
| Other, net | Other, net | | 61 | | | 13 | | | Other, net | | 109 | | | 64 | | | 77 | | | 109 | |
| | 2,092 | | | 1,279 | | | | 1,961 | | | 3,052 | | | 3,991 | | | 6,880 | |
OPERATING EXPENSES: | OPERATING EXPENSES: | | | | | | OPERATING EXPENSES: | | | | | | | | |
Lease operating expenses | Lease operating expenses | | 264 | | | 335 | | | Lease operating expenses | | 361 | | | 359 | | | 682 | | | 703 | |
Gathering, processing, and transmission | | 58 | | | 71 | | | |
Purchased oil and gas costs | | 494 | | | 86 | | | |
Gathering, processing, and transmission(1) | | Gathering, processing, and transmission(1) | | 78 | | | 94 | | | 156 | | | 175 | |
Purchased oil and gas costs(1) | | Purchased oil and gas costs(1) | | 131 | | | 528 | | | 347 | | | 879 | |
Taxes other than income | Taxes other than income | | 44 | | | 33 | | | Taxes other than income | | 50 | | | 78 | | | 102 | | | 148 | |
Exploration | Exploration | | 49 | | | 57 | | | Exploration | | 43 | | | 56 | | | 95 | | | 98 | |
General and administrative | General and administrative | | 83 | | | 68 | | | General and administrative | | 72 | | | 89 | | | 137 | | | 245 | |
Transaction, reorganization, and separation | Transaction, reorganization, and separation | | 0 | | | 27 | | | Transaction, reorganization, and separation | | 2 | | | 3 | | | 6 | | | 17 | |
Depreciation, depletion, and amortization | Depreciation, depletion, and amortization | | 342 | | | 566 | | | Depreciation, depletion, and amortization | | 367 | | | 278 | | | 699 | | | 569 | |
Asset retirement obligation accretion | Asset retirement obligation accretion | | 28 | | | 27 | | | Asset retirement obligation accretion | | 29 | | | 29 | | | 57 | | | 58 | |
Impairments | Impairments | | 0 | | | 4,472 | | | Impairments | | 46 | | | — | | | 46 | | | — | |
Financing costs, net | Financing costs, net | | 110 | | | 103 | | | Financing costs, net | | 82 | | | 76 | | | 154 | | | 228 | |
| | 1,472 | | | 5,845 | | | | 1,261 | | | 1,590 | | | 2,481 | | | 3,120 | |
NET INCOME (LOSS) BEFORE INCOME TAXES | | 620 | | | (4,566) | | | |
NET INCOME BEFORE INCOME TAXES | | NET INCOME BEFORE INCOME TAXES | | 700 | | | 1,462 | | | 1,510 | | | 3,760 | |
Current income tax provision | Current income tax provision | | 149 | | | 89 | | | Current income tax provision | | 254 | | | 415 | | | 600 | | | 807 | |
Deferred income tax provision (benefit) | Deferred income tax provision (benefit) | | 21 | | | (33) | | | Deferred income tax provision (benefit) | | (16) | | | (20) | | | 122 | | | (60) | |
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | | 450 | | | (4,622) | | | |
Net income (loss) attributable to noncontrolling interest - Egypt | | 42 | | | (151) | | | |
Net income (loss) attributable to noncontrolling interest - Altus | | 1 | | | (9) | | | |
Net income attributable to Altus Preferred Unit limited partners | | 19 | | | 18 | | | |
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK | | $ | 388 | | | $ | (4,480) | | | |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | | NET INCOME INCLUDING NONCONTROLLING INTERESTS | | 462 | | | 1,067 | | | 788 | | | 3,013 | |
Net income attributable to noncontrolling interest – Egypt | | Net income attributable to noncontrolling interest – Egypt | | 81 | | | 141 | | | 165 | | | 260 | |
Net income attributable to noncontrolling interest – Altus | | Net income attributable to noncontrolling interest – Altus | | — | | | — | | | — | | | 14 | |
Net loss attributable to Altus Preferred Unit limited partners | | Net loss attributable to Altus Preferred Unit limited partners | | — | | | — | | | — | | | (70) | |
NET INCOME ATTRIBUTABLE TO COMMON STOCK | | NET INCOME ATTRIBUTABLE TO COMMON STOCK | | $ | 381 | | | $ | 926 | | | $ | 623 | | | $ | 2,809 | |
| NET INCOME (LOSS) PER COMMON SHARE: | | | |
| NET INCOME PER COMMON SHARE: | | NET INCOME PER COMMON SHARE: | |
Basic | Basic | | $ | 1.02 | | | $ | (11.86) | | | Basic | | $ | 1.24 | | | $ | 2.72 | | | $ | 2.01 | | | $ | 8.18 | |
| Diluted | Diluted | | $ | 1.02 | | | $ | (11.86) | | | Diluted | | $ | 1.23 | | | $ | 2.71 | | | $ | 2.01 | | | $ | 8.15 | |
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | | | WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: | |
Basic | Basic | | 378 | | | 378 | | | Basic | | 308 | | | 341 | | | 310 | | | 344 | |
Diluted | Diluted | | 379 | | | 378 | | | Diluted | | 309 | | | 342 | | | 310 | | | 344 | |
|
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited)
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2021 | | 2020 | | | | |
| | (In millions) |
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | | $ | 450 | | | $ | (4,622) | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | | | | | | | | |
Share of equity method interests other comprehensive income (loss) | | 1 | | | (1) | | | | | |
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS | | 451 | | | (4,623) | | | | | |
Comprehensive income (loss) attributable to noncontrolling interest - Egypt | | 42 | | | (151) | | | | | |
Comprehensive income (loss) attributable to noncontrolling interest - Altus | | 1 | | | (9) | | | | | |
Comprehensive income attributable to Altus Preferred Unit limited partners | | 19 | | | 18 | | | | | |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK | | $ | 389 | | | $ | (4,481) | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
NET INCOME INCLUDING NONCONTROLLING INTERESTS | | $ | 462 | | | $ | 1,067 | | | $ | 788 | | | $ | 3,013 | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | | | | | | | | |
| | | | | | | | |
Pension and postretirement benefit plan | | — | | | — | | | 3 | | | (1) | |
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS | | 462 | | | 1,067 | | | 791 | | | 3,012 | |
Comprehensive income attributable to noncontrolling interest – Egypt | | 81 | | | 141 | | | 165 | | | 260 | |
Comprehensive income attributable to noncontrolling interest – Altus | | — | | | — | | | — | | | 14 | |
Comprehensive loss attributable to Altus Preferred Unit limited partners | | — | | | — | | | — | | | (70) | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK | | $ | 381 | | | $ | 926 | | | $ | 626 | | | $ | 2,808 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | For the Six Months Ended June 30, |
| | | For the Three Months Ended March 31, | | | 2023 | | 2022 |
| | | 2021 | | 2020 | | | | |
| | | (In millions) | | | (In millions) |
CASH FLOWS FROM OPERATING ACTIVITIES: | CASH FLOWS FROM OPERATING ACTIVITIES: | | CASH FLOWS FROM OPERATING ACTIVITIES: | |
Net income (loss) including noncontrolling interests | | $ | 450 | | | $ | (4,622) | | |
Adjustments to reconcile net loss to net cash provided by operating activities: | | |
Unrealized derivative instrument losses (gains), net | | (10) | | | 103 | | |
Net income including noncontrolling interests | | Net income including noncontrolling interests | | $ | 788 | | | $ | 3,013 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | Adjustments to reconcile net income to net cash provided by operating activities: | |
Unrealized derivative instrument (gains) losses, net | | Unrealized derivative instrument (gains) losses, net | | (80) | | | 83 | |
Gain on divestitures, net | Gain on divestitures, net | | (2) | | | (25) | | Gain on divestitures, net | | (6) | | | (1,149) | |
Exploratory dry hole expense and unproved leasehold impairments | Exploratory dry hole expense and unproved leasehold impairments | | 37 | | | 43 | | Exploratory dry hole expense and unproved leasehold impairments | | 64 | | | 47 | |
Depreciation, depletion, and amortization | Depreciation, depletion, and amortization | | 342 | | | 566 | | Depreciation, depletion, and amortization | | 699 | | | 569 | |
Asset retirement obligation accretion | Asset retirement obligation accretion | | 28 | | | 27 | | Asset retirement obligation accretion | | 57 | | | 58 | |
Impairments | Impairments | | 0 | | | 4,472 | | Impairments | | 46 | | | — | |
Provision for (benefit from) deferred income taxes | Provision for (benefit from) deferred income taxes | | 21 | | | (33) | | Provision for (benefit from) deferred income taxes | | 122 | | | (60) | |
(Gain) loss on extinguishment of debt | | (Gain) loss on extinguishment of debt | | (9) | | | 67 | |
| Other | | (20) | | | (8) | | |
Other, net | | Other, net | | (67) | | | (88) | |
Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
Receivables | Receivables | | (168) | | | 221 | | Receivables | | 100 | | | (519) | |
Inventories | Inventories | | (3) | | | 30 | | Inventories | | (45) | | | (18) | |
Drilling advances and other current assets | Drilling advances and other current assets | | 10 | | | (26) | | Drilling advances and other current assets | | 2 | | | 28 | |
Deferred charges and other long-term assets | Deferred charges and other long-term assets | | (10) | | | (7) | | Deferred charges and other long-term assets | | 160 | | | (11) | |
Accounts payable | Accounts payable | | 75 | | | (80) | | Accounts payable | | (112) | | | 206 | |
Accrued expenses | Accrued expenses | | (66) | | | (173) | | Accrued expenses | | (163) | | | 202 | |
Deferred credits and noncurrent liabilities | Deferred credits and noncurrent liabilities | | (13) | | | 14 | | Deferred credits and noncurrent liabilities | | (221) | | | (2) | |
NET CASH PROVIDED BY OPERATING ACTIVITIES | NET CASH PROVIDED BY OPERATING ACTIVITIES | | 671 | | | 502 | | NET CASH PROVIDED BY OPERATING ACTIVITIES | | 1,335 | | | 2,426 | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | CASH FLOWS FROM INVESTING ACTIVITIES: | | CASH FLOWS FROM INVESTING ACTIVITIES: | |
Additions to upstream oil and gas property | Additions to upstream oil and gas property | | (253) | | | (511) | | Additions to upstream oil and gas property | | (1,119) | | | (741) | |
Additions to Altus gathering, processing, and transmission (GPT) facilities | | (1) | | | (19) | | |
| Leasehold and property acquisitions | Leasehold and property acquisitions | | (2) | | | (1) | | Leasehold and property acquisitions | | (10) | | | (26) | |
Contributions to Altus equity method interests | | (21) | | | (83) | | |
Proceeds from sale of oil and gas properties | | Proceeds from sale of oil and gas properties | | 28 | | | 751 | |
Proceeds from sale of Kinetik shares | | Proceeds from sale of Kinetik shares | | — | | | 224 | |
Deconsolidation of Altus cash and cash equivalents | | Deconsolidation of Altus cash and cash equivalents | | — | | | (143) | |
Other, net | | Other, net | | (14) | | | (49) | |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES | | NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES | | (1,115) | | | 16 | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | CASH FLOWS FROM FINANCING ACTIVITIES: | |
Proceeds from (payments on) revolving credit facilities, net | | Proceeds from (payments on) revolving credit facilities, net | | 196 | | | (267) | |
| Proceeds from sale of oil and gas properties | | 3 | | | 126 | | |
Other, net | | 7 | | | (21) | | |
NET CASH USED IN INVESTING ACTIVITIES | | (267) | | | (509) | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | |
Proceeds from (payments on) Apache credit facility, net | | (85) | | | 250 | | |
Proceeds from Altus credit facility, net | | 33 | | | 72 | | |
| Payments on Apache fixed-rate debt | Payments on Apache fixed-rate debt | | (6) | | | 0 | | Payments on Apache fixed-rate debt | | (65) | | | (1,370) | |
Distributions to noncontrolling interest - Egypt | | (40) | | | (32) | | |
Distributions to Altus Preferred Unit limited partners | | (11) | | | 0 | | |
Distributions to noncontrolling interest – Egypt | | Distributions to noncontrolling interest – Egypt | | (100) | | | (159) | |
Treasury stock activity, net | | Treasury stock activity, net | | (188) | | | (552) | |
Dividends paid to APA common stockholders | | Dividends paid to APA common stockholders | | (155) | | | (86) | |
Other, net | | Other, net | | (11) | | | (28) | |
NET CASH USED IN FINANCING ACTIVITIES | | NET CASH USED IN FINANCING ACTIVITIES | | (323) | | | (2,462) | |
| Dividends paid | | (9) | | | (94) | | |
Other | | (10) | | | (8) | | |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | | (128) | | | 188 | | |
| NET INCREASE IN CASH AND CASH EQUIVALENTS | | 276 | | | 181 | | |
NET DECREASE IN CASH AND CASH EQUIVALENTS | | NET DECREASE IN CASH AND CASH EQUIVALENTS | | (103) | | | (20) | |
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | | 262 | | | 247 | | CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | | 245 | | | 302 | |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 538 | | | $ | 428 | | CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 142 | | | $ | 282 | |
| SUPPLEMENTARY CASH FLOW DATA: | SUPPLEMENTARY CASH FLOW DATA: | | SUPPLEMENTARY CASH FLOW DATA: | |
Interest paid, net of capitalized interest | Interest paid, net of capitalized interest | | $ | 113 | | | $ | 126 | | Interest paid, net of capitalized interest | | $ | 168 | | | $ | 172 | |
Income taxes paid, net of refunds | Income taxes paid, net of refunds | | 124 | | | 98 | | Income taxes paid, net of refunds | | 476 | | | 637 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
| | | | | | | | | | | | | | |
| | March 31, 2021 | | December 31, 2020 |
| | (In millions, except share data) |
ASSETS | | | | |
CURRENT ASSETS: | | | | |
Cash and cash equivalents ($51 and $24 related to Altus VIE) | | $ | 538 | | | $ | 262 | |
Receivables, net of allowance of $98 and $95 | | 1,071 | | | 908 | |
Other current assets (Note 5) ($12 and $5 related to Altus VIE) | | 736 | | | 676 | |
| | 2,345 | | | 1,846 | |
PROPERTY AND EQUIPMENT: | | | | |
Oil and gas properties | | 42,054 | | | 41,819 | |
| | | | |
| | | | |
Gathering, processing, and transmission facilities ($206 and $206 related to Altus VIE) | | 671 | | | 670 | |
Other ($3 and $3 related to Altus VIE) | | 1,139 | | | 1,140 | |
| | | | |
Less: Accumulated depreciation, depletion, and amortization ($16 and $13 related to Altus VIE) | | (35,146) | | | (34,810) | |
| | 8,718 | | | 8,819 | |
OTHER ASSETS: | | | | |
Equity method interests (Note 6) ($1,567 and $1,555 related to Altus VIE) | | 1,567 | | | 1,555 | |
Deferred charges and other ($6 and $5 related to Altus VIE) | | 497 | | | 526 | |
| | $ | 13,127 | | | $ | 12,746 | |
| | | | |
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY | | | | |
CURRENT LIABILITIES: | | | | |
Accounts payable | | $ | 524 | | | $ | 444 | |
Current debt | | 2 | | | 2 | |
Other current liabilities (Note 7) ($8 and $4 related to Altus VIE) | | 812 | | | 862 | |
| | 1,338 | | | 1,308 | |
LONG-TERM DEBT (Note 9) ($657 and $624 related to Altus VIE) | | 8,713 | | | 8,770 | |
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: | | | | |
Income taxes | | 237 | | | 215 | |
Asset retirement obligation (Note 8) ($65 and $64 related to Altus VIE) | | 1,914 | | | 1,888 | |
Other ($161 and $144 related to Altus VIE) | | 581 | | | 602 | |
| | 2,732 | | | 2,705 | |
| | | | |
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12) | | 605 | | | 608 | |
EQUITY (DEFICIT): | | | | |
Common stock, $0.625 par, 860,000,000 shares authorized, 418,917,594 and 418,429,375 shares issued, respectively | | 262 | | | 262 | |
Paid-in capital | | 11,727 | | | 11,735 | |
Accumulated deficit | | (10,073) | | | (10,461) | |
Treasury stock, at cost, 40,944,759 and 40,946,745 shares, respectively | | (3,189) | | | (3,189) | |
Accumulated other comprehensive income | | 15 | | | 14 | |
APA SHAREHOLDERS’ DEFICIT | | (1,258) | | | (1,639) | |
Noncontrolling interest - Egypt | | 927 | | | 925 | |
Noncontrolling interest - Altus | | 70 | | | 69 | |
TOTAL DEFICIT | | (261) | | | (645) | |
| | $ | 13,127 | | | $ | 12,746 | |
| | | | | | | | | | | | | | |
| | June 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions, except share data) |
ASSETS | | | | |
CURRENT ASSETS: | | | | |
Cash and cash equivalents | | $ | 142 | | | $ | 245 | |
Receivables, net of allowance of $103 and $117 | | 1,364 | | | 1,466 | |
| | 1,093 | | | 997 | |
| | 2,599 | | | 2,708 | |
PROPERTY AND EQUIPMENT: | | | | |
Oil and gas properties | | 43,384 | | | 42,356 | |
Gathering, processing, and transmission facilities | | 447 | | | 449 | |
Other | | 598 | | | 613 | |
Less: Accumulated depreciation, depletion, and amortization | | (35,061) | | | (34,406) | |
| | 9,368 | | | 9,012 | |
OTHER ASSETS: | | | | |
Equity method interests (Note 6) | | 695 | | | 624 | |
Decommissioning security for sold Gulf of Mexico properties (Note 11) | | 57 | | | 217 | |
Deferred charges and other | | 525 | | | 586 | |
| | $ | 13,244 | | | $ | 13,147 | |
| | | | |
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY (DEFICIT) | | | | |
CURRENT LIABILITIES: | | | | |
Accounts payable | | $ | 656 | | | $ | 771 | |
Current debt | | 2 | | | 2 | |
Other current liabilities (Note 7) | | 1,972 | | | 2,143 | |
| | 2,630 | | | 2,916 | |
| | 5,574 | | | 5,451 | |
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: | | | | |
Income taxes | | 449 | | | 314 | |
Asset retirement obligation (Note 8) | | 1,984 | | | 1,940 | |
Decommissioning contingency for sold Gulf of Mexico properties (Note 11) | | 472 | | | 738 | |
Other | | 439 | | | 443 | |
| | 3,344 | | | 3,435 | |
| | | | |
EQUITY (DEFICIT): | | | | |
Common stock, $0.625 par, 860,000,000 shares authorized, 420,584,819 and 419,869,987 shares issued, respectively | | 263 | | | 262 | |
Paid-in capital | | 11,267 | | | 11,420 | |
Accumulated deficit | | (5,191) | | | (5,814) | |
Treasury stock, at cost, 113,319,877 and 108,310,838 shares, respectively | | (5,647) | | | (5,459) | |
Accumulated other comprehensive income | | 17 | | | 14 | |
APA SHAREHOLDERS’ EQUITY | | 709 | | | 423 | |
Noncontrolling interest – Egypt | | 987 | | | 922 | |
| | | | |
TOTAL EQUITY | | 1,696 | | | 1,345 | |
| | $ | 13,244 | | | $ | 13,147 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTINTERESTS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners | | | Common Stock | | Paid-In Capital | | Accumulated Deficit | | Treasury Stock | | Accumulated Other Comprehensive Income (Loss) | | APA SHAREHOLDERS’ EQUITY (DEFICIT) | | Noncontrolling Interests | | TOTAL EQUITY (DEFICIT) |
| | | | | (In millions) |
For the Quarter Ended March 31, 2020 | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2019 | | $ | 555 | | | | $ | 261 | | | $ | 11,769 | | | $ | (5,601) | | | $ | (3,190) | | | $ | 16 | | | $ | 3,255 | | | $ | 1,210 | | | $ | 4,465 | |
Net loss attributable to common stock | | — | | | | — | | | — | | | (4,480) | | | — | | | — | | | (4,480) | | | — | | | (4,480) | |
Net loss attributable to noncontrolling interest - Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (151) | | | (151) | |
Net loss attributable to noncontrolling interest - Altus | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (9) | | | (9) | |
| | | | | | | | | | | | | | | | | | | |
Net income attributable to Altus Preferred Unit holders | | 18 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Distributions to noncontrolling interest - Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (32) | | | (32) | |
Common dividends ($0.025 per share) | | — | | | | — | | | (10) | | | — | | | — | | | — | | | (10) | | | — | | | (10) | |
Other | | — | | | | 1 | | | (12) | | | — | | | 1 | | | (1) | | | (11) | | | — | | | (11) | |
Balance at March 31, 2020 | | $ | 573 | | | | $ | 262 | | | $ | 11,747 | | | $ | (10,081) | | | $ | (3,189) | | | $ | 15 | | | $ | (1,246) | | | $ | 1,018 | | | $ | (228) | |
| | | | | | | | | | | | | | | | | | | |
For the Quarter Ended March 31, 2021 | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2020 | | $ | 608 | | | | $ | 262 | | | $ | 11,735 | | | $ | (10,461) | | | $ | (3,189) | | | $ | 14 | | | $ | (1,639) | | | $ | 994 | | | $ | (645) | |
Net income attributable to common stock | | — | | | | — | | | — | | | 388 | | | — | | | — | | | 388 | | | — | | | 388 | |
Net income attributable to noncontrolling interest - Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 42 | | | 42 | |
Net income attributable to noncontrolling interest - Altus | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | | | | | | | | | |
Net income attributable to Altus Preferred Unit limited partners | | 19 | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Distributions payable to Altus Preferred Unit limited partners | | (11) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Distributions paid to Altus Preferred Unit limited partners | | (11) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Distributions to noncontrolling interest - Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (40) | | | (40) | |
Common dividends ($0.025 per share) | | — | | | | — | | | (9) | | | — | | | — | | | — | | | (9) | | | — | | | (9) | |
Other | | — | | | | — | | | 1 | | | — | | | — | | | 1 | | | 2 | | | — | | | 2 | |
Balance at March 31, 2021 | | $ | 605 | | | | $ | 262 | | | $ | 11,727 | | | $ | (10,073) | | | $ | (3,189) | | | $ | 15 | | | $ | (1,258) | | | $ | 997 | | | $ | (261) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 Quarter Ended June 30, 2022 | | | | | | | | | | | | | | | | | | | |
Balance at March 31, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,600 | | | $ | (7,605) | | | $ | (4,296) | | | $ | 21 | | | $ | (18) | | | $ | 870 | | | $ | 852 | |
Net income attributable to common stock | | — | | | | — | | | — | | | 926 | | | — | | | — | | | 926 | | | — | | | 926 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 141 | | | 141 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (90) | | | (90) | |
Common dividends declared ($0.125 per share) | | — | | | | — | | | (42) | | | — | | | — | | | — | | | (42) | | | — | | | (42) | |
| | | | | | | | | | | | | | | | | | | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (291) | | | — | | | (291) | | | — | | | (291) | |
Other | | — | | | | — | | | 9 | | | — | | | — | | | — | | | 9 | | | — | | | 9 | |
Balance at June 30, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,567 | | | $ | (6,679) | | | $ | (4,587) | | | $ | 21 | | | $ | 584 | | | $ | 921 | | | $ | 1,505 | |
| | | | | | | | | | | | | | | | | | | |
For the Quarter Ended June 30, 2023 | | | | | | | | | | | | | | | | | | | |
Balance at March 31, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,337 | | | $ | (5,572) | | | $ | (5,601) | | | $ | 17 | | | $ | 444 | | | $ | 989 | | | $ | 1,433 | |
Net income attributable to common stock | | — | | | | — | | | — | | | 381 | | | — | | | — | | | 381 | | | — | | | 381 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 81 | | | 81 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (83) | | | (83) | |
Common dividends declared ($0.25 per share) | | — | | | | — | | | (77) | | | — | | | — | | | — | | | (77) | | | — | | | (77) | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (46) | | | — | | | (46) | | | — | | | (46) | |
| | | | | | | | | | | | | | | | | | | |
Other | | — | | | | — | | | 7 | | | — | | | — | | | — | | | 7 | | | — | | | 7 | |
Balance at June 30, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,267 | | | $ | (5,191) | | | $ | (5,647) | | | $ | 17 | | | $ | 709 | | | $ | 987 | | | $ | 1,696 | |
The accompanying notes to consolidated financial statements are an integral part of this statement.
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 Six Months Ended June 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 | | — | | | | | | | | 2,809 | | | — | | | — | | | 2,809 | | | — | | | 2,809 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 260 | | | 260 | |
Net income attributable to noncontrolling interest – Altus | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 14 | | | 14 | |
Net loss attributable to Altus Preferred Unit limited partners | | (70) | | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (159) | | | (159) | |
Common dividends declared ($0.25 per share) | | — | | | | — | | | (85) | | | — | | | — | | | — | | | (85) | | | — | | | (85) | |
Deconsolidation of Altus | | (642) | | | | — | | | — | | | — | | | — | | | — | | | — | | | (72) | | | (72) | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (551) | | | — | | | (551) | | | — | | | (551) | |
Other | | — | | | | — | | | 7 | | | — | | | — | | | (1) | | | 6 | | | — | | | 6 | |
Balance at June 30, 2022 | | $ | — | | | | $ | 262 | | | $ | 11,567 | | | $ | (6,679) | | | $ | (4,587) | | | $ | 21 | | | $ | 584 | | | $ | 921 | | | $ | 1,505 | |
| | | | | | | | | | | | | | | | | | | |
For the Six Months Ended June 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 | | — | | | | — | | | — | | | 623 | | | — | | | — | | | 623 | | | — | | | 623 | |
Net income attributable to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | 165 | | | 165 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
Distributions to noncontrolling interest – Egypt | | — | | | | — | | | — | | | — | | | — | | | — | | | — | | | (100) | | | (100) | |
Common dividends declared ($0.50 per share) | | — | | | | — | | | (155) | | | — | | | — | | | — | | | (155) | | | — | | | (155) | |
| | | | | | | | | | | | | | | | | | | |
Treasury stock activity, net | | — | | | | — | | | — | | | — | | | (188) | | | — | | | (188) | | | — | | | (188) | |
Other | | — | | | | 1 | | | 2 | | | — | | | — | | | 3 | | | 6 | | | — | | | 6 | |
Balance at June 30, 2023 | | $ | — | | | | $ | 263 | | | $ | 11,267 | | | $ | (5,191) | | | $ | (5,647) | | | $ | 17 | | | $ | 709 | | | $ | 987 | | | $ | 1,696 | |
5The 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 discussed below.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 of Apache Corporation, the Company’s predecessor registrant, for the fiscal year ended December 31, 2020,2022, which contains a summary of the Company’s significant accounting policies and other disclosures.
On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly-owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The holding company structure modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of March 31, 2021,June 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 Apache Corporation’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.2022. 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 implementation of the Holding Company Reorganization was accounted for as a merger under common control. APA recognized the assets and liabilities of Apache at carryover basis. The consolidated financial statements of APA present comparative information for prior years on a combined basis, as if both APA and Apache were under common control for all periods presented.
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. 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 ownowned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM)(ALTM or Altus), which iswas reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualifiesqualified as a variable interest entity under GAAP, for which APA consolidatesconsolidated because a wholly-ownedwholly owned subsidiary of APA hashad 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 variable interest entity 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’s proportionate share ofCompany elected the results of operations generated by thefair value option to account for its equity method interests are recorded as a component of “Other, net” under “Revenues and Other”interest in the Company’s statement of consolidated operations.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 requirerequires 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. The Company determines fair value measurements in accordance with Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), which provides a hierarchy that prioritizes and defines the types of inputs used to basemeasure fair value measurements.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).
Fair value measurements are recorded on a nonrecurring basis when certain qualitative assessments of the Company’s assets indicate potential impairment. Asset impairments recorded in connection with fair value assessments were as follows:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2021 | | 2020 | | | | |
| | (In millions) |
Oil and gas proved property | | $ | 0 | | | $ | 4,299 | | | | | |
Gathering, processing, and transmission facilities | | 0 | | | 68 | | | | | |
Goodwill | | 0 | | | 87 | | | | | |
| | | | | | | | |
Inventory and other | | 0 | | | 18 | | | | | |
Total Impairments | | $ | 0 | | | $ | 4,472 | | | | | |
During the first quarter of 2021,three and six months ended June 30, 2023 and 2022, the Company recorded 0no 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 six months ended June 30, 2023 and 2022.
Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales, in each case, net of allowance for credit losses, were $1.2 billion and $1.3 billion as of June 30, 2023 and December 31, 2022, respectively.
Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation 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 first quarter of 2020,three and six months ended June 30, 2023, the Company recorded asset$46 million of impairments totaling $4.5 billion in connection with fair value assessments. Givenvaluations of drilling and operations equipment inventory upon the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment based on the net book value of its assets as of March 31, 2020. The Company recognized proved property impairments totaling $3.9 billion, $354 million, and $7 millionCompany’s decision to suspend drilling operations in the U.S., Egypt, and North Sea, respectively, to reduce the carrying value of its oil and gas properties to the estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”Sea.
During the first quarter of 2020, the Company also recognized impairments of $13 million for the early termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.
During the first quarter of 2020, the Company performed an interim impairment analysis of the goodwill related to its Egypt reporting segment. Reductions in the estimated net present value of expected future cash flows from oil and gas properties resulted in fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in the first quarter of 2020.
The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2021 | | 2020 | | | | |
| | (In millions) |
Proved Properties: | | | | | | | | |
U.S. | | $ | 0 | | | $ | 3,938 | | | | | |
Egypt | | 0 | | | 354 | | | | | |
North Sea | | 0 | | | 7 | | | | | |
Total proved properties | | $ | 0 | | | $ | 4,299 | | | | | |
| | | | | | | | |
Unproved Properties: | | | | | | | | |
U.S. | | $ | 16 | | | $ | 17 | | | | | |
Egypt | | 2 | | | 2 | | | | | |
| | | | | | | | |
Total unproved properties | | $ | 18 | | | $ | 19 | | | | | |
Proved properties impaired during the first quarter of 2020 had an aggregate fair value of $1.9 billion as of March 31, 2020.
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 totaled $671 million and $670 million at March 31, 2021 and December 31, 2020, respectively, with accumulated depreciation for these assets totaling $342 million and $323 million for the respective periods. 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.
The Company assessed its long-lived infrastructure assets for impairment at March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.
Revenue Recognition
There have been no significant changes to the Company’s contracts with customers during the three months ended March 31, 2021 and 2020.
Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, totaled $957 million and $670 million as of March 31, 2021 and December 31, 2020, respectively.
Oil and gas production revenues from non-customers were $106 million and $48 million during the first quarter of 2021 and 2020, respectively, and represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations. Refer to Note 14—Business Segment Information for a disaggregation of revenue by product and reporting segment.In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Transaction, Reorganization, and Separation (TRS)
In recent years, the Company streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. In light of the continued streamlining of the Company’s asset portfolio through divestitures and strategic transactions, in late 2019 management initiated a comprehensive redesign of the Company’s organizational structure and operations. Efforts related to this reorganization were substantially completed during 2020. The Company incurred and paid a cumulative total of $79 million of reorganization costs through December 31, 2020.
The Company recorded $27 million of TRS costs during the first quarter of 2020. TRS costs incurred in the first three months of 2020 related to $25 million of separation costs associated with the reorganization and $2 million for transaction consulting fees.
2. ACQUISITIONS AND DIVESTITURES
20212023 Activity
During the second quarter and first quartersix months of 2021,2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $2 million. Theapproximately $4 million and $10 million, respectively.
During the second quarter and first six months of 2023, the Company also completed the sale of certain non-core assets and leasehold primarily in the Permian Basin, in multiple transactions for total cash proceeds of $3 million. The Company recognized$7 million and $28 million, respectively, recognizing a gain of approximately $2$5 million and $6 million, respectively, upon closing of these transactions during the first quarter of 2021.transactions.
20202022 Activity
During the second quarter and first quartersix months of 2020,2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $1$26 million. The
During the second quarter and first six months of 2022, the Company also completed the sale of certain non-core assets and leasehold primarily in the Permian Basin, in multiple transactions for total cash proceeds of $45 million.$7 million and $15 million, respectively, recognizing a gain of approximately $1 million and $2 million, respectively, upon closing of these transactions.
During the first six 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 $6$609 million upon closingthat reflects the difference between the Company’s share of these transactions duringALTM’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 2020.
Suriname Joint Venture Agreement
In December 2019,2022, the Company entered into a joint venture agreement with Total S.A. to exploresold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and develop Block 58 offshore Suriname. Under the terms of the agreement, the Company and Total S.A. each hold a 50 percent working interest in Block 58. Pursuant to the agreement, the Company operated the drilling of the first four wells, the Maka Central-1, Sapakara West-1, Kwaskwasi-1, and Keskesi East-1, and subsequently transferred operatorship of Block 58 to Total S.A. on January 1, 2021; however, the Company continued to operate the Keskesi exploration well until completion of drilling operations during the first quarter of 2021.
In connection with the agreement, the Company received $100 million from Total S.A. upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019. All proceeds were applied against the carrying value of the Company’s Suriname properties and associated inventory. The Company recognized a $19loss of $25 million, gain in the first quarter of 2020 associated with the transaction.
The Company will also receive various other forms of consideration, including
$5 billion of cash carry on the Company’s first $7.5 billion of appraisal and development capital, 25 percent cash carry on all of the Company’s appraisal and development capital beyond the first $7.5 billion, a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.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 $237$547 million and $197$474 million at March 31, 2021as of June 30, 2023 and December 31, 2020,2022, respectively. The increase is primarily attributable to additional drilling activity offshore Suriname and in Suriname, partially offset by dry hole write-offs during the period. Egypt.
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 also 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 March 31, 2021,June 30, 2023, the Company had derivative positions with 10seven 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 commodity prices, currency exchange rates, or interest rates.
Derivative Instruments
Commodity Derivative Instruments
As of March 31, 2021, the Company had the following open crude oil derivative positions:
| | | | | | | | | | | | | | | | | | | | |
| | | | Fixed-Price Swaps |
Production Period | | Settlement Index | | Mbbls | | Weighted Average Fixed Price(1)(2) |
April—June 2021 | | NYMEX WTI | | 5,642 | | | $61.20 |
July—September 2021 | | NYMEX WTI | | 1,472 | | | $60.18 |
October—December 2021 | | NYMEX WTI | | 1,012 | | | $58.59 |
April—June 2021 | | Dated Brent | | 2,366 | | | $64.20 |
July—September 2021 | | Dated Brent | | 414 | | | $63.14 |
October—December 2021 | | Dated Brent | | 828 | | | $61.44 |
(1)Subsequent to March 31, 2021, the Company entered into fixed-price crude oil contracts settling against NYMEX WTI totaling 6,000 Bbls/d at a weighted average price of $60.10 for the third quarter of 2021.
(2)Subsequent to March 31, 2021, the Company entered into fixed-price crude oil contracts settling against Platts Dated Brent totaling 19,714 Bbls/d at a weighted average price of $64.07 for the second quarter of 2021 and 13,500 Bbls/d at a weighted average price of $63.06 for the third quarter of 2021.
As of March 31, 2021, the Company had the following open crude oil financial basis swap contracts:
| | | | | | | | | | | | | | | | | | | | |
Production Period | | Settlement Index | | Mbbls | | Weighted Average Price Differential |
May—June 2021 | | Midland-WTI/Cushing-WTI | | 3,782 | | | $0.56 |
July—September 2021 | | Midland-WTI/Cushing-WTI | | 2,024 | | | $0.61 |
October—December 2021 | | Midland-WTI/Cushing-WTI | | 1,012 | | | $0.70 |
As of March 31, 2021,June 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 |
April—December 2021 | | NYMEX Henry Hub/IF Waha | | 37,580 | | | $(0.43) | | — | | | — |
April—December 2021 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 37,580 | | | $(0.07) |
January—December 2022 | | NYMEX Henry Hub/IF Waha | | 43,800 | | | $(0.45) | | — | | | — |
January—December 2022 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 43,800 | | | $(0.08) |
Embedded Derivatives
Altus Preferred Units Embedded Derivative
During the second quarter of 2019, Altus Midstream LP issued and sold Series A Cumulative redeemable Preferred Units (Preferred Units). Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, refer to “Fair Value Measurements” below and Note 12—Redeemable Noncontrolling Interest - Altus.Pipeline Capacity Embedded Derivatives
During the fourth quarter of 2019 and first quarter of 2020, the Company entered into separate agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements are arrangements under which the Company has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. These features require bifurcation and measurement of the change in market values for each period. Unrealized gains or losses in the fair value of these features are recorded as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received will be deferred and reflected in income over the original tenure of the transportation agreement.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 |
July—September 2023 | | NYMEX Henry Hub/IF Waha | | 1,840 | | | $(1.62) | | — | | | — |
July—September 2023 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 1,840 | | | $(0.19) |
July—December 2023 | | NYMEX Henry Hub/IF Waha | | 36,800 | | | $(1.15) | | — | | | — |
July—December 2023 | | NYMEX Henry Hub/IF HSC | | — | | | — | | 36,800 | | | $(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 | | | 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 | | 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) | | | | | | | | | | | | |
March 31, 2021 | | |
| | | (In millions) |
June 30, 2023 | | June 30, 2023 | |
Assets: | | Assets: | |
Commodity derivative instruments | | Commodity derivative instruments | | $ | — | | | $ | 36 | | | $ | — | | | $ | 36 | | | $ | — | | | $ | 36 | |
| | December 31, 2022 | | December 31, 2022 | |
Assets: | Assets: | | Assets: | |
Commodity derivative instruments | Commodity derivative instruments | | $ | 0 | | | $ | 39 | | | $ | 0 | | | $ | 39 | | | $ | (1) | | | $ | 38 | | Commodity derivative instruments | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | | | $ | — | | | $ | 5 | |
Liabilities: | Liabilities: | | Liabilities: | |
Commodity derivative instruments | Commodity derivative instruments | | 0 | | | 2 | | | 0 | | | 2 | | | (1) | | | 1 | | Commodity derivative instruments | | — | | | 50 | | | — | | | 50 | | | — | | | 50 | |
Pipeline capacity embedded derivatives | | 0 | | | 52 | | | 0 | | | 52 | | | 0 | | | 52 | | |
Preferred Units embedded derivative | | 0 | | | 0 | | | 156 | | | 156 | | | 0 | | | 156 | | |
| December 31, 2020 | | |
Assets: | | |
Commodity derivative instruments | | $ | 0 | | | $ | 11 | | | $ | 0 | | | $ | 11 | | | $ | 0 | | | $ | 11 | | |
Liabilities: | | |
Pipeline capacity embedded derivative | | 0 | | | 53 | | | 0 | | | 53 | | | 0 | | | 53 | | |
Preferred Units embedded derivative | | 0 | | | 0 | | | 139 | | | 139 | | | 0 | | | 139 | | |
|
(1)The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.counterparties and reclassifications between long-term and short-term balances.
The fair values of the Company’s derivative instruments and pipeline capacity embedded derivatives 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.
The fair value of the Preferred Units embedded derivative is calculated using an income approach, a Level 3 fair value measurement. The fair value determination is based on a range of factors, including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the March 31, 2021 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quantitative Information About Level 3 Fair Value Measurements |
| | Fair Value at March 31, 2021 | | Valuation Technique | | Significant Unobservable Inputs | | Range/Value |
| | (In millions) | | | | | | |
Preferred Units embedded derivative | | $ | 156 | | | Option Model | | Altus’ Imputed Interest Rate | | 7.15-12.51% |
| | | | | | Interest Rate Volatility | | 38.75% |
A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of March 31, 2021, while a one percent decrease would lead to a similar decrease in value as of March 31, 2021. The assumed expected timing until exercise of the exchange option at March 31, 2021 was 5.20 years.
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:
| | | | | | | | | | | | | | | June 30, 2023 | | December 31, 2022 |
| | March 31, 2021 | | December 31, 2020 | | | | |
| | (In millions) | | (In millions) |
Current Assets: Other current assets | Current Assets: Other current assets | | $ | 34 | | | $ | 6 | | Current Assets: Other current assets | | $ | 36 | | | $ | — | |
Other Assets: Deferred charges and other | Other Assets: Deferred charges and other | | 4 | | | 5 | | Other Assets: Deferred charges and other | | — | | | 5 | |
Total derivative assets | Total derivative assets | | $ | 38 | | | $ | 11 | | Total derivative assets | | $ | 36 | | | $ | 5 | |
| Current Liabilities: Other current liabilities | Current Liabilities: Other current liabilities | | $ | 1 | | | $ | 0 | | Current Liabilities: Other current liabilities | | $ | — | | | $ | 50 | |
Deferred Credits and Other Noncurrent Liabilities: Other | | 208 | | | 192 | | |
| Total derivative liabilities | Total derivative liabilities | | $ | 209 | | | $ | 192 | | 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 June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | | 2023 | | 2022 | | 2023 | | 2022 |
| 2021 | | 2020 | | | | | | | | | |
| | | (In millions) | | | (In millions) |
Realized: | Realized: | | | Realized: | |
Commodity derivative instruments | Commodity derivative instruments | | $ | 148 | | | $ | 1 | | | Commodity derivative instruments | | $ | 4 | | | $ | (4) | | | $ | 24 | | | $ | (9) | |
Foreign currency derivative instruments | Foreign currency derivative instruments | | 0 | | | (1) | | | Foreign currency derivative instruments | | — | | | (2) | | | — | | | (2) | |
Realized gain, net | | 148 | | | 0 | | | |
Realized gains (losses), net | | Realized gains (losses), net | | 4 | | | (6) | | | 24 | | | (11) | |
Unrealized: | Unrealized: | | | Unrealized: | |
Commodity derivative instruments | Commodity derivative instruments | | 26 | | | 17 | | | Commodity derivative instruments | | 47 | | | (20) | | | 80 | | | (44) | |
Pipeline capacity embedded derivatives | | 1 | | | (53) | | | |
| Foreign currency derivative instruments | Foreign currency derivative instruments | | 0 | | | (5) | | | Foreign currency derivative instruments | | — | | | (6) | | | — | | | (8) | |
Preferred units embedded derivative | | (17) | | | (62) | | | |
Unrealized gain (loss), net | | 10 | | | (103) | | | |
Preferred Units embedded derivative | | Preferred Units embedded derivative | | — | | | — | | | — | | | (31) | |
Unrealized gains (losses), net | | Unrealized gains (losses), net | | 47 | | | (26) | | | 80 | | | (83) | |
Derivative instrument gains (losses), net | Derivative instrument gains (losses), net | | $ | 158 | | | $ | (103) | | | Derivative instrument gains (losses), net | | $ | 51 | | | $ | (32) | | | $ | 104 | | | $ | (94) | |
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, (gains), net” inunder “Adjustments to reconcile net lossincome to net cash provided by operating activities.”
As part of the Company’s ordinary course of business, the Company seeks to maintain a balance between “first of month” and “gas daily pricing” for its U.S. natural gas portfolio and sales activities in a given month. This is typically implemented through a combination of physical and financial contracts that settle monthly. In January 2021, the Company entered into financial contracts that increased its exposure to “gas daily pricing” and reduced its exposure to “first of month” pricing for February 2021. The Company realized a gain of $147 million in connection with these contracts in the first quarter of 2021 as a result of extreme daily gas price volatility across Texas in February resulting from Winter Storm Uri.
5. OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets:
| | | | | | | | | | | | | | | June 30, 2023 | | December 31, 2022 |
| | March 31, 2021 | | December 31, 2020 | | | | |
| | | (In millions) | | | (In millions) |
Inventories | Inventories | | $ | 502 | | | $ | 492 | | Inventories | | $ | 488 | | | $ | 427 | |
Drilling advances | Drilling advances | | 111 | | | 113 | | Drilling advances | | 90 | | | 89 | |
| Prepaid assets and other | Prepaid assets and other | | 123 | | | 71 | | Prepaid assets and other | | 65 | | | 31 | |
Current decommissioning security for sold Gulf of Mexico assets | | Current decommissioning security for sold Gulf of Mexico assets | | 450 | | | 450 | |
Total Other current assets | Total Other current assets | | $ | 736 | | | $ | 676 | | Total Other current assets | | $ | 1,093 | | | $ | 997 | |
6. EQUITY METHOD INTERESTS
As of March 31, 2021 and December 31, 2020, the Company, through its ownership of Altus, had the following equity method interests in 4 Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentagesKinetik Class A Common Stock held by the Company and associated carrying valuesis treated as an interest in equity securities measured at fair value. The Company elected the fair value option for each entity:
| | | | | | | | | | | | | | | | | | | | |
| | Interest | | March 31, 2021 | | December 31, 2020 |
| | | | (In millions) |
Gulf Coast Express Pipeline, LLC | | 16.0% | | $ | 281 | | | $ | 284 | |
EPIC Crude Holdings, LP | | 15.0% | | 172 | | | 176 | |
Permian Highway Pipeline, LLC | | 26.7% | | 639 | | | 615 | |
Shin Oak Pipeline (Breviloba, LLC) | | 33.0% | | 475 | | | 480 | |
Total Altus equity method interests | | | | $ | 1,567 | | | $ | 1,555 | |
As of March 31, 2021 and December 31, 2020, unamortized basis differences included in themeasuring its equity method interest balances were $37 millionin Kinetik based on practical expedience, variances in reporting timelines, and $38 million, respectively. These amounts represent differencescost-benefit considerations. The fair value of the Company’s interest in Altus’ contributions to dateKinetik 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 Altus’ underlying equityother” in the separate net assets withinCompany’s statement of consolidated operations.
The Company’s initial interest in Kinetik was measured at fair value based on the financial statementsCompany’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the respective entities. Unamortized basis differences will be amortized into net income overCompany 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 useful livesCompany’s statement of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. During the underlying pipeline assets.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 following table presents the activity in Altus’ equity method interests for the three months ended March 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Gulf Coast Express Pipeline LLC | | EPIC Crude Holdings, LP | | Permian Highway Pipeline LLC | | Breviloba, LLC | | Total |
| | (In millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Balance at December 31, 2020 | | $ | 284 | | | $ | 176 | | | $ | 615 | | | $ | 480 | | | $ | 1,555 | |
Capital contributions | | 0 | | | 0 | | | 21 | | | 0 | | | 21 | |
Distributions | | (12) | | | 0 | | | (8) | | | (11) | | | (31) | |
| | | | | | | | | | |
Equity income (loss), net(1) | | 9 | | | (5) | | | 11 | | | 6 | | | 21 | |
Accumulated other comprehensive income | | 0 | | | 1 | | | 0 | | | 0 | | | 1 | |
Balance at March 31, 2021 | | $ | 281 | | | $ | 172 | | | $ | 639 | | | $ | 475 | | | $ | 1,567 | |
(1)Company has received approximately 2.1 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through June 30, 2023. As of March 31, 2021,June 30, 2023, the amountCompany’s ownership of consolidated earnings, net19.8 million shares represented approximately 13 percent of amortization basis differences, which represents undistributed earnings, was $3 million from Permian Highway Pipeline LLC.Kinetik’s outstanding Class A Common Stock.
Summarized Combined Financial InformationThe Company recorded changes in the fair value of its equity method interest in Kinetik totaling gains of $90 million and $42 million in the second quarters of 2023 and 2022, respectively, and gains of $71 million and $66 million in the first six months of 2023 and 2022, respectively. These gains were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.
The following table presents summarized selected income statement data for Altus’ equity method interests (on a 100 percent basis):represents sales and costs associated with Kinetik:
| | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, |
| | 2021 | | 2020 |
| | (In millions) |
Operating revenues | | $ | 254 | | | $ | 176 | |
Operating income | | 112 | | | 86 | |
Net income | | 89 | | | 77 | |
Other comprehensive income (loss) | | 4 | | | (8) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Natural gas and NGLs sales | | $ | 29 | | | $ | — | | | $ | 43 | | | $ | — | |
Purchased oil and gas sales | | 7 | | | — | | | 7 | | | — | |
| | $ | 36 | | | $ | — | | | $ | 50 | | | $ | — | |
| | | | | | | | |
Gathering, processing, and transmission costs | | $ | 29 | | | $ | 26 | | | $ | 55 | | | $ | 36 | |
Purchased oil and gas costs | | 26 | | | — | | | 28 | | | — | |
| | $ | 55 | | | $ | 26 | | | $ | 83 | | | $ | 36 | |
As of June 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $39 million and receivables from Kinetik of approximately $22 million.
7. OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities:
| | | | | | | | | | | | | | | June 30, 2023 | | December 31, 2022 |
| | March 31, 2021 | | December 31, 2020 | | | | |
| | | (In millions) | | | (In millions) |
Accrued operating expenses | Accrued operating expenses | | $ | 92 | | | $ | 91 | | Accrued operating expenses | | $ | 174 | | | $ | 145 | |
Accrued exploration and development | Accrued exploration and development | | 185 | | | 167 | | Accrued exploration and development | | 384 | | | 333 | |
| Accrued compensation and benefits | Accrued compensation and benefits | | 91 | | | 170 | | Accrued compensation and benefits | | 247 | | | 514 | |
Accrued interest | Accrued interest | | 138 | | | 140 | | Accrued interest | | 95 | | | 97 | |
Accrued income taxes | Accrued income taxes | | 41 | | | 25 | | Accrued income taxes | | 193 | | | 90 | |
Current asset retirement obligation | Current asset retirement obligation | | 56 | | | 56 | | Current asset retirement obligation | | 55 | | | 55 | |
Current operating lease liability | Current operating lease liability | | 106 | | | 116 | | Current operating lease liability | | 102 | | | 167 | |
| Current decommissioning contingency for sold Gulf of Mexico properties | | Current decommissioning contingency for sold Gulf of Mexico properties | | 450 | | | 450 | |
Other | Other | | 103 | | | 97 | | Other | | 272 | | | 292 | |
Total Other current liabilities | Total Other current liabilities | | $ | 812 | | | $ | 862 | | Total Other current liabilities | | $ | 1,972 | | | $ | 2,143 | |
8. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
| | | | | | | | |
| | March 31,June 30,
20212023
|
| | (In millions) |
Asset retirement obligation, December 31, 20202022 | | $ | 1,9441,995 | |
Liabilities incurred | | 18 | |
| | |
Liabilities settled | | (3)(21) | |
| | |
| | |
| | |
Accretion expense | | 2857 | |
| | |
Asset retirement obligation, March 31, 2021June 30, 2023 | | 1,9702,039 | |
Less current portion | | (56)(55) | |
Asset retirement obligation, long-term | | $ | 1,9141,984 | |
9. DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
| | | | | | | | | | | | | | | June 30, 2023 | | December 31, 2022 |
| | March 31, 2021 | | December 31, 2020 | | | | |
| | (In millions) | | (In millions) |
Apache notes and debentures before unamortized discount and debt issuance costs(1) | Apache notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 8,045 | | | $ | 8,052 | | Apache notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 4,835 | | | $ | 4,908 | |
Altus credit facility(2) | | 657 | | | 624 | | |
Apache credit facility(2) | | 65 | | | 150 | | |
| Syndicated credit facilities(2) | | Syndicated credit facilities(2) | | 762 | | | 566 | |
Apache finance lease obligations | Apache finance lease obligations | | 37 | | | 38 | | Apache finance lease obligations | | 33 | | | 34 | |
Unamortized discount | Unamortized discount | | (34) | | | (35) | | Unamortized discount | | (27) | | | (27) | |
Debt issuance costs | Debt issuance costs | | (55) | | | (57) | | Debt issuance costs | | (27) | | | (28) | |
Total debt | Total debt | | 8,715 | | | 8,772 | | Total debt | | 5,576 | | | 5,453 | |
Current maturities | Current maturities | | (2) | | | (2) | | Current maturities | | (2) | | | (2) | |
Long-term debt | Long-term debt | | $ | 8,713 | | | $ | 8,770 | | Long-term debt | | $ | 5,574 | | | $ | 5,451 | |
(1)The fair values of the Apache notes and debentures were $8.0$4.1 billion and $8.5$4.2 billion as of March 31, 2021June 30, 2023 and December 31, 2020,2022, 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.
AsAt each of March 31, 2021June 30, 2023 and December 31, 2020,2022, current debt included $2 million of finance lease obligations.
During the quartersix months ended March 31, 2021,June 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $7$74 million for an aggregate purchase price of $6$65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $1$10 million. NaNThe Company recognized a $9 million gain or loss was recognized on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
In March 2018,During the six months ended June 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 six months ended June 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 atwo 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 totaling $4.0 billion. In March 2019, the term of this facility was extended by one yearUS$1.8 billion (including a letter of credit subfacility of up to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exerciseUS$750 million, of an extension option. Apache canwhich US$150 million currently is committed). The Company may increase commitments up to $5.0an 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, includeswith 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 letterNew 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 subfacility ofthen 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 $3.0 billion,an aggregate principal amount of which $2.08 billion was committed asUS$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of March 31, 2021. The facilityindebtedness under senior notes and debentures outstanding under Apache’s existing indentures is for general corporate purposes. less than US$1.0 billion.
As of March 31, 2021,June 30, 2023, there were $65$762 million of borrowings under the USD Agreement and an aggregate £573 million and $20£590 million in letters of credit outstanding under this facility.the GBP Agreement. As of June 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2020,2022, there were $150$566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £633 million and $40£652 million in letters of credit outstanding under this facility.the GBP Agreement. The outstanding 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.
Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in Apache’s credit ratings during 2020, the Company does not expect that Apache’s commercial paper program will be cost competitive with its other financing alternatives and does not anticipate Apache using it under such circumstances. As of March 31, 2021 and December 31, 2020, 0 commercial paper was outstanding.
Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2021June 30, 2023 and December 31, 2020,2022, there were 0no outstanding borrowings under these facilities. As of June 30, 2023, there were £185 million and £34$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.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s 2, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of March 31, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and 0 letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache, APA Corporation, or any of its subsidiaries.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
| | | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | | 2023 | | 2022 | | 2023 | | 2022 |
| | | 2021 | | 2020 | | | | | | | | | |
| | | (In millions) | | | (In millions) |
Interest expense | Interest expense | | $ | 112 | | | $ | 107 | | | Interest expense | | $ | 89 | | | $ | 79 | | | $ | 177 | | | $ | 169 | |
Amortization of debt issuance costs | Amortization of debt issuance costs | | 2 | | | 2 | | | Amortization of debt issuance costs | | 1 | | | 5 | | | 2 | | | 7 | |
Capitalized interest | Capitalized interest | | (2) | | | (4) | | | Capitalized interest | | (5) | | | (5) | | | (11) | | | (8) | |
| (Gain) loss on extinguishment of debt | | (Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | |
Interest income | Interest income | | (2) | | | (2) | | | Interest income | | (3) | | | (3) | | | (5) | | | (7) | |
Financing costs, net | Financing costs, net | | $ | 110 | | | $ | 103 | | | Financing costs, net | | $ | 82 | | | $ | 76 | | | $ | 154 | | | $ | 228 | |
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 firstsecond quarter of 2021,2023, 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 firstsecond quarter of 2020,2022, the Company’s effective income tax rate was primarily impacted by oila 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, and gas impairments, a goodwill impairment, and an increasedecrease 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 within 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 statestates and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.
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.controls, which also may include controls related to the potential impacts of climate change. As of March 31, 2021,June 30, 2023, the Company has an accrued liability of approximately $62$52 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. ForWith respect to material matters thatfor 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 Apache Corporation’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.2022.
Argentine Environmental Claims
On March 12, 2014, the Company and Argentina Tariff
No material change inits subsidiaries completed the statussale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad AnónimaAnonima (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 indemnities matter has occurred since(Pioneer) in an amount up to $45 million pursuant to the filingterms and conditions of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration
As more fully described in Apache Corporation’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020,2022, 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 2020,2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. Some of the cases have been remanded to state court with the remand orders being appealed. 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 areasarea of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Courttrial 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’ appeal is pending.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 their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.
Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, 4four 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.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 purported 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 Company believes that Plaintiffs’ claims lack meritsettlement is subject to court approval and will not have a material adverse effect onis expected to be finalized by the Company’s financial position, resultsend of operation, or liquidity.2023.
California and Delaware Litigation
On July 17, 2017, in 3three separate actions, San Mateo County, California,and Marin County, California,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 2two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action onfiled similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuits against many of the same defendants.lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The remand decision, and further activity in the cases, has been stayed pending further appellate review.
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 believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.
Castex Lawsuit
In a case styled Apache Corporation v. Castex Offshore, Inc,Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Company’s appeal is pending.Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company.
Oklahoma Class ActionsKulp Minerals Lawsuit
The Company isOn or about April 7, 2023, Apache was sued in a party to 2 purported class actionsaction in OklahomaNew Mexico styled Bigie Lee RheaKulp Minerals LLC v. Apache Corporation, Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219.D-506-CV-2023-00352 in the Fifth Judicial District. The Rhea case has been certified and includes a class of royalty owners seeking damages in excess of $250 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The AllenKulp Minerals case has not been certified and seeks to represent a group of owners who have allegedly receivedowed statutory interest under New Mexico law as a result of purported late royaltyoil and other payments under Oklahoma statutes.gas payments. The amount of this claim is not yet reasonably determinable. While adverse judgments against the Company are possible, theThe Company intends to vigorously defend these lawsuits and claims.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, (1) alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) alleges that 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) alleges that thesecertain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) alleges that, as a result, the Company’s public statements were materially false and misleading. On March 4, 2021, another lawsuit, captioned Brian Schwegel v. Apache Corporation, et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging identical allegations. The Company believes that all plaintiffs’ claims lack merit and intends to vigorously defend these lawsuits.this lawsuit.
On March 16, 2021,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 334th151st District Court of Harris County, Texas. TheThen, on July 21, 2023, a case purportscaptioned 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 a derivative actionactions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe the plaintiff’sthat plaintiffs’ claims lack merit and intend to vigorously defend this lawsuit.these lawsuits.
Environmental Matters
As of March 31, 2021,June 30, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $2$1 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and respondinghas responded to the information request. The EPA has not commencedreferred the notice for civil enforcement proceedings, andproceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and respondinghas responded to the information request. The EPA has not commencedreferred the notice for civil enforcement proceedings, andproceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
The Company was recently served with two lawsuits filed in Lea County, New Mexico: William O. Stephens v. Apache Corporation; No. D-506-CV-2023-00632, in the Fifth Judicial District and Merchant Livestock Company v. Apache Corporation, Exxon Corporation, et al.; No. D-506-CV-2023-00664, in the Fifth Judicial District. Each lawsuit alleges property damage and environmental impacts from previous oil and gas operations that require remediation. The Company disputes that it is responsible for the damages claimed and/or relief sought and intends to vigorously defend each lawsuit. At this time, the Company is unable to reasonably estimate whether either lawsuit, individually, will result in damages that are more or less than $100,000, exclusive of interest and costs.
The Company is not aware of any environmental claims existing as of March 31, 2021June 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 Asset RetirementDecommissioning Obligations on Sold Properties
In 2013, the CompanyApache sold its Gulf of Mexico (GOM) Shelf operations and properties (Legacyand its GOM Assets)operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the CompanyApache received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date.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 liabilities,obligations, Fieldwood posted letters of credit in favor of the CompanyApache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a trust account (Trust A),beneficiary and which iswere funded by a 10 percenttwo net profits interestinterests (NPIs) depending on future oil prices and of which the Company is the beneficiary.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 the CompanyApache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit.Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, the CompanyApache holds two bonds (Bonds) and the remainingfive Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Legacy GOM Assets as and when such abandonment and decommissioning obligations areApache is required to be performedperform 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. Fieldwood has submitted aOn 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 of reorganization, andbecame effective. Pursuant to the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan, would separate the Legacy GOM Assets were separated into a standalone company, andwhich 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 forto fund 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 AROs. IfBureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the proceedsdecommissioning obligations that it is currently obligated to perform on certain of production are insufficient forthe 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 AROs, thennotices to BSEE in the Company expectsfuture and that it may be required by the relevant governmental authoritiesreceive additional orders from BSEE requiring it to perform such AROs,decommission other Legacy GOM Assets.
As of June 30, 2023, Apache has incurred $464 million in which casedecommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will applynot, 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 $276 million had been reimbursed from Trust A as of June 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 reimbursement from the Bonds remainingand the Letters of Credit until all such funds and Trust A to pay for the AROs.securities are fully utilized. In addition, after such sources have been exhausted, the CompanyApache 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 foregoingcombination 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 CompanyStandby Loan Agreement, then Apache may be forced to effectively use its available cash to coverfund the deficit.
As of June 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 $922 million to $1.1 billion on an undiscounted basis. Management does not believe any additionalspecific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $922 million as of June 30, 2023, representing the estimated costs of decommissioning it incursmay be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $472 million is reflected under the caption “Decommissioning contingency for performing such AROs.
12. REDEEMABLE NONCONTROLLING INTEREST - ALTUS
Preferred Units Issuance
On June 12, 2019, Altus Midstream LP issuedsold Gulf of Mexico properties,” and sold Preferred Units for an aggregate issue price of $625$450 million is reflected under “Other current liabilities” in a private offering exempt from the registration requirements of the Securities Act (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers.
Classification
The carrying amount of the Preferred Units are recorded as “Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet basedsheet. 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 June 30, 2023, the Company has also recorded a $507 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $57 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 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 termsLetters 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 Preferred Units, including281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the redemption rights with respect thereto.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. Apache believes that Insurers’ claims lack merit, intends to vigorously defend these claims, and will vigorously pursue counterclaims.
Measurement
Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price.
Activity related to the Preferred Units is as follows:
| | | | | | | | | | | | | | |
| | Units Outstanding | | Financial Position(1) |
| | (In millions, except unit data) |
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019 | | 638,163 | | | $ | 555 | |
Distribution of in-kind additional Preferred Units | | 22,531 | | | 0 | |
Cash distributions to Altus Preferred Unit limited partners | | — | | | (23) | |
Allocation of Altus Midstream LP net income | | N/A | | 76 | |
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020 | | 660,694 | | | 608 | |
| | | | |
Cash distributions to Altus Preferred Unit limited partners | | — | | | (11) | |
Dividends payable to Altus Preferred Unit limited partners | | — | | | (11) | |
Allocation of Altus Midstream LP net income | | N/A | | 19 | |
Redeemable noncontrolling interest — Preferred Unit at: March 31, 2021 | | 660,694 | | | 605 | |
Preferred Units embedded derivative | | | | 156 | |
| | | | $ | 761 | |
(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of March 31, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of March 31, 2021, the Redemption Price would have been based on a 1.3 times multiple of invested capital, which was $813 million. This was greater than using an 11.5 percent internal rate of return, which would equate to a redemption value of $713 million.
N/A - not applicable.
13.12. CAPITAL STOCK
Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a 1-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache's stock plans along with all of Apache's rights and obligations under each plan.
Net Income (Loss) per Common Share
The following table presents a reconciliation of the components of basic and diluted net income (loss) per common share in the consolidated financial statements:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, |
| | 2021 | | 2020 |
| | Income | | Shares | | Per Share | | Loss | | Shares | | Per Share |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Income (loss) attributable to common stock | | $ | 388 | | | 378 | | | $ | 1.02 | | | $ | (4,480) | | | 378 | | | $ | (11.86) | |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | 0 | | | 1 | | | $ | 0 | | | $ | 0 | | | 0 | | | $ | 0 | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Income (loss) attributable to common stock | | $ | 388 | | | 379 | | | $ | 1.02 | | | $ | (4,480) | | | 378 | | | $ | (11.86) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended June 30, |
| | 2023 | | 2022 |
| | Income | | Shares | | Per Share | | Income | | Shares | | Per Share |
| | | | | | | | | | | | |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 381 | | | 308 | | | $ | 1.24 | | | $ | 926 | | | 341 | | | $ | 2.72 | |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — | | | 1 | | | $ | (0.01) | | | $ | — | | | 1 | | | $ | (0.01) | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 381 | | | 309 | | | $ | 1.23 | | | $ | 926 | | | 342 | | | $ | 2.71 | |
| | For the Six Months Ended June 30, |
| | 2023 | | 2022 |
| | Income | | Shares | | Per Share | | Income | | Shares | | Per Share |
| | | | | | | | | | | | |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 623 | | | 310 | | | $ | 2.01 | | | $ | 2,809 | | | 344 | | | $ | 8.18 | |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — | | | — | | | $ | — | | | $ | — | | | — | | | $ | (0.03) | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income attributable to common stock | | $ | 623 | | | 310 | | | $ | 2.01 | | | $ | 2,809 | | | 344 | | | $ | 8.15 | |
The Company uses the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream LP for shares of Altus Midstream Company’s common stock. The impact to net income and loss attributable to common stock on an assumed conversion of the Preferred Units was anti-dilutive for the quarter ended March 31, 2021 and 2020. The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 4.0of 2.1 million and 5.52.0 million forduring the quarter ended March 31, 2021second quarters of 2023 and 2020,2022, respectively, and 2.2 million and 2.7 million during the first six months of 2023 and 2022, respectively.
Stock Repurchase Program
In 2013 and 2014,During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock, and duringstock. During the fourth quarter of 2018,2021, the Company’s Board of Directors authorized the purchase of up toan additional 40 million additional 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 second quarter of 2023, the Company repurchased 1.3 million shares at an average price of $33.72 per share. For the six months ended June 30, 2023, the Company repurchased 5 million shares at an average price of $37.53 per share, and as of June 30, 2023, the Company had remaining authorization to repurchase up to 48 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the second quarter of 2022, the Company repurchased 7.0 million shares at an average price of $41.60 per share. For the six months ended June 30, 2022, the Company repurchased 14.2 million shares at an average price of $38.79 per share. The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through March 31, 2021, had repurchased a total of 40 million shares at an average price of $79.18 per share. The Company is not obligated to acquire any specific number of shares and did 0t purchase any shares during the three months ended March 31, 2021.
Common Stock DividendsDividend
For the quarterquarters ended March 31, 2021June 30, 2023 and 2020,2022, the Company paid $9$77 million and $94$43 million, respectively, in dividends on its common stock. InFor the firstsix months ended June 30, 2023 and 2022, the Company paid $155 million and $86 million, respectively, in dividends on its common stock.
During the third quarter of 2020,2022, the Company’s Board of Directors approved a reduction in the Company’san increase to its quarterly dividend from $0.125 to $0.25 per share from $0.25 to $0.025, effective for all dividends payable after March 12, 2020.share.
14.13. BUSINESS SEGMENT INFORMATION
As of March 31, 2021,June 30, 2023, the Company isCompany’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across 3three 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. APA’sPrior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business iswas operated by Altus Midstream Company,ALTM, which owns, develops,owned, developed, and operatesoperated a midstream energy asset network in the Permian Basin of West Texas. APAThe 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 | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(1) | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total |
| | Upstream | | | Upstream | |
For the Quarter Ended March 31, 2021 | | (In millions) | |
| For the Quarter Ended June 30, 2023 | | For the Quarter Ended June 30, 2023 | | (In millions) |
Revenues: | Revenues: | | Revenues: | |
Oil revenues | Oil revenues | | $ | 402 | | | $ | 241 | | | $ | 348 | | | $ | 0 | | | $ | 0 | | | $ | 991 | | Oil revenues | | $ | 618 | | | $ | 235 | | | $ | 512 | | | $ | — | | | $ | — | | | $ | 1,365 | |
Natural gas revenues | Natural gas revenues | | 70 | | | 31 | | | 211 | | | 0 | | | 0 | | | 312 | | Natural gas revenues | | 90 | | | 39 | | | 51 | | | — | | | — | | | 180 | |
Natural gas liquids revenues | Natural gas liquids revenues | | 2 | | | 6 | | | 120 | | | 0 | | | 0 | | | 128 | | Natural gas liquids revenues | | — | | | 4 | | | 103 | | | — | | | — | | | 107 | |
Oil, natural gas, and natural gas liquids production revenues | Oil, natural gas, and natural gas liquids production revenues | | 474 | | | 278 | | | 679 | | | 0 | | | — | | | 1,431 | | Oil, natural gas, and natural gas liquids production revenues | | 708 | | | 278 | | | 666 | | | — | | | — | | | 1,652 | |
Purchased oil and gas sales | Purchased oil and gas sales | | 0 | | | 0 | | | 437 | | | 3 | | | 0 | | | 440 | | Purchased oil and gas sales | | — | | | — | | | 144 | | | — | | | — | | | 144 | |
Midstream service affiliate revenues | | — | | | — | | | — | | | 32 | | | (32) | | | 0 | | |
| | | 474 | | | 278 | | | 1,116 | | | 35 | | | (32) | | | 1,871 | | | 708 | | | 278 | | | 810 | | | — | | | — | | | 1,796 | |
Operating Expenses: | Operating Expenses: | | Operating Expenses: | |
Lease operating expenses | Lease operating expenses | | 104 | | | 75 | | | 86 | | | 0 | | | (1) | | | 264 | | Lease operating expenses | | 121 | | | 99 | | | 141 | | | — | | | — | | | 361 | |
Gathering, processing, and transmission | Gathering, processing, and transmission | | 1 | | | 12 | | | 69 | | | 7 | | | (31) | | | 58 | | Gathering, processing, and transmission | | 6 | | | 12 | | | 60 | | | — | | | — | | | 78 | |
Purchased oil and gas costs | Purchased oil and gas costs | | 0 | | | 0 | | | 492 | | | 2 | | | 0 | | | 494 | | Purchased oil and gas costs | | — | | | — | | | 131 | | | — | | | — | | | 131 | |
Taxes other than income | Taxes other than income | | 0 | | | 0 | | | 40 | | | 4 | | | 0 | | | 44 | | Taxes other than income | | — | | | — | | | 50 | | | — | | | — | | | 50 | |
Exploration | Exploration | | 8 | | | 20 | | | 16 | | | 0 | | | 5 | | | 49 | | Exploration | | 30 | | | 4 | | | 3 | | | — | | | 6 | | | 43 | |
Depreciation, depletion, and amortization | Depreciation, depletion, and amortization | | 130 | | | 84 | | | 125 | | | 3 | | | 0 | | | 342 | | Depreciation, depletion, and amortization | | 126 | | | 61 | | | 180 | | | — | | | — | | | 367 | |
Asset retirement obligation accretion | Asset retirement obligation accretion | | 0 | | | 19 | | | 8 | | | 1 | | | 0 | | | 28 | | Asset retirement obligation accretion | | — | | | 19 | | | 10 | | | — | | | — | | | 29 | |
Impairments | Impairments | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | Impairments | | — | | | 46 | | | — | | | — | | | — | | | 46 | |
| | 243 | | | 210 | | | 836 | | | 17 | | | (27) | | | 1,279 | | | 283 | | | 241 | | | 575 | | | — | | | 6 | | | 1,105 | |
Operating Income (Loss)(2) | Operating Income (Loss)(2) | | $ | 231 | | | $ | 68 | | | $ | 280 | | | $ | 18 | | | $ | (5) | | | 592 | | Operating Income (Loss)(2) | | $ | 425 | | | $ | 37 | | | $ | 235 | | | $ | — | | | $ | (6) | | | 691 | |
| Other Income (Expense): | Other Income (Expense): | | Other Income (Expense): | |
Derivative instrument gains, net | Derivative instrument gains, net | | 158 | | Derivative instrument gains, net | | 51 | |
| Gain on divestitures, net | Gain on divestitures, net | | 2 | | Gain on divestitures, net | | 5 | |
Other | | 61 | | |
Other, net | | Other, net | | 109 | |
General and administrative | General and administrative | | (83) | | General and administrative | | (72) | |
| Transaction, reorganization, and separation | | Transaction, reorganization, and separation | | (2) | |
Financing costs, net | Financing costs, net | | (110) | | Financing costs, net | | (82) | |
Income Before Income Taxes | Income Before Income Taxes | | $ | 620 | | Income Before Income Taxes | | $ | 700 | |
| | | | | Total Assets(3) | | $ | 3,020 | | | $ | 2,167 | | | $ | 5,633 | | | $ | 1,828 | | | $ | 479 | | | $ | 13,127 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Six Months Ended June 30, 2023 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 1,247 | | | $ | 517 | | | $ | 998 | | | $ | — | | | $ | — | | | $ | 2,762 | |
Natural gas revenues | | 183 | | | 99 | | | 140 | | | — | | | — | | | 422 | |
Natural gas liquids revenues | | — | | | 14 | | | 223 | | | — | | | — | | | 237 | |
Oil, natural gas, and natural gas liquids production revenues | | 1,430 | | | 630 | | | 1,361 | | | — | | | — | | | 3,421 | |
Purchased oil and gas sales | | — | | | — | | | 383 | | | — | | | — | | | 383 | |
| | | | | | | | | | | | |
| | 1,430 | | | 630 | | | 1,744 | | | — | | | — | | | 3,804 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 218 | | | 176 | | | 288 | | | — | | | — | | | 682 | |
Gathering, processing, and transmission | | 13 | | | 23 | | | 120 | | | — | | | — | | | 156 | |
Purchased oil and gas costs | | — | | | — | | | 347 | | | — | | | — | | | 347 | |
Taxes other than income | | — | | | — | | | 102 | | | — | | | — | | | 102 | |
Exploration | | 66 | | | 9 | | | 6 | | | — | | | 14 | | | 95 | |
Depreciation, depletion, and amortization | | 249 | | | 119 | | | 331 | | | — | | | — | | | 699 | |
Asset retirement obligation accretion | | — | | | 37 | | | 20 | | | — | | | — | | | 57 | |
Impairments | | — | | | 46 | | | — | | | — | | | — | | | 46 | |
| | 546 | | | 410 | | | 1,214 | | | — | | | 14 | | | 2,184 | |
Operating Income (Loss)(2) | | $ | 884 | | | $ | 220 | | | $ | 530 | | | $ | — | | | $ | (14) | | | 1,620 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
Derivative instrument gains, net | | | | | | | | | | | | 104 | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 6 | |
Other, net | | | | | | | | | | | | 77 | |
General and administrative | | | | | | | | | | | | (137) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (6) | |
Financing costs, net | | | | | | | | | | | | (154) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 1,510 | |
| | | | | | | | | | | | |
Total Assets(3) | | $ | 3,365 | | | $ | 1,719 | | | $ | 7,640 | | | $ | — | | | $ | 520 | | | $ | 13,244 | |
| | | Egypt | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(1) | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | Upstream | |
For the Quarter Ended March 31, 2020 | | (In millions) | |
| For the Quarter Ended June 30, 2022 | | For the Quarter Ended June 30, 2022 | | (In millions) |
Revenues: | Revenues: | | Revenues: | |
Oil revenues | Oil revenues | | $ | 333 | | | $ | 271 | | | $ | 428 | | | $ | 0 | | | $ | 0 | | | $ | 1,032 | | Oil revenues | | $ | 902 | | | $ | 307 | | | $ | 654 | | | $ | — | | | $ | — | | | $ | 1,863 | |
Natural gas revenues | Natural gas revenues | | 65 | | | 19 | | | 39 | | | 0 | | | 0 | | | 123 | | Natural gas revenues | | 88 | | | 64 | | | 281 | | | — | | | — | | | 433 | |
Natural gas liquids revenues | Natural gas liquids revenues | | 3 | | | 7 | | | 71 | | | 0 | | | 0 | | | 81 | | Natural gas liquids revenues | | 3 | | | 12 | | | 214 | | | — | | | — | | | 229 | |
Oil, natural gas, and natural gas liquids production revenues | Oil, natural gas, and natural gas liquids production revenues | | 401 | | | 297 | | | 538 | | | 0 | | | — | | | 1,236 | | Oil, natural gas, and natural gas liquids production revenues | | 993 | | | 383 | | | 1,149 | | | — | | | — | | | 2,525 | |
Purchased oil and gas sales | Purchased oil and gas sales | | 0 | | | 0 | | | 108 | | | 0 | | | 0 | | | 108 | | Purchased oil and gas sales | | — | | | — | | | 522 | | | — | | | — | | | 522 | |
Midstream service affiliate revenues | | — | | | — | | | — | | | 41 | | | (41) | | | — | | |
| | | 401 | | | 297 | | | 646 | | | 41 | | | (41) | | | 1,344 | | | 993 | | | 383 | | | 1,671 | | | — | | | — | | | 3,047 | |
Operating Expenses: | Operating Expenses: | | Operating Expenses: | |
Lease operating expenses | Lease operating expenses | | 112 | | | 81 | | | 143 | | | 0 | | | (1) | | | 335 | | Lease operating expenses | | 131 | | | 118 | | | 110 | | | — | | | — | | | 359 | |
Gathering, processing, and transmission | Gathering, processing, and transmission | | 10 | | | 16 | | | 74 | | | 11 | | | (40) | | | 71 | | Gathering, processing, and transmission | | 5 | | | 12 | | | 77 | | | — | | | — | | | 94 | |
Purchased oil and gas costs | Purchased oil and gas costs | | 0 | | | 0 | | | 86 | | | 0 | | | 0 | | | 86 | | Purchased oil and gas costs | | — | | | — | | | 528 | | | — | | | — | | | 528 | |
Taxes other than income | Taxes other than income | | 0 | | | 0 | | | 30 | | | 3 | | | 0 | | | 33 | | Taxes other than income | | — | | | — | | | 78 | | | — | | | — | | | 78 | |
Exploration | Exploration | | 18 | | | 2 | | | 35 | | | 0 | | | 2 | | | 57 | | Exploration | | 12 | | | 2 | | | 1 | | | — | | | 41 | | | 56 | |
Depreciation, depletion, and amortization | Depreciation, depletion, and amortization | | 161 | | | 109 | | | 293 | | | 3 | | | 0 | | | 566 | | Depreciation, depletion, and amortization | | 91 | | | 54 | | | 133 | | | — | | | — | | | 278 | |
Asset retirement obligation accretion | Asset retirement obligation accretion | | 0 | | | 18 | | | 8 | | | 1 | | | 0 | | | 27 | | Asset retirement obligation accretion | | — | | | 20 | | | 9 | | | — | | | — | | | 29 | |
Impairments | | 509 | | | 7 | | | 3,956 | | | 0 | | | 0 | | | 4,472 | | |
| | | 810 | | | 233 | | | 4,625 | | | 18 | | | (39) | | | 5,647 | | | 239 | | | 206 | | | 936 | | | — | | | 41 | | | 1,422 | |
Operating Income (Loss)(2) | Operating Income (Loss)(2) | | $ | (409) | | | $ | 64 | | | $ | (3,979) | | | $ | 23 | | | $ | (2) | | | (4,303) | | Operating Income (Loss)(2) | | $ | 754 | | | $ | 177 | | | $ | 735 | | | $ | — | | | $ | (41) | | | 1,625 | |
| Other Income (Expense): | Other Income (Expense): | | Other Income (Expense): | |
| Derivative instrument losses, net | Derivative instrument losses, net | | (103) | | Derivative instrument losses, net | | (32) | |
Gain on divestitures | | 25 | | |
Other | | 13 | | |
Loss on divestitures, net | | Loss on divestitures, net | | (27) | |
Other, net | | Other, net | | 64 | |
General and administrative | General and administrative | | (68) | | General and administrative | | (89) | |
Transaction, reorganization, and separation | Transaction, reorganization, and separation | | (27) | | Transaction, reorganization, and separation | | (3) | |
Financing costs, net | Financing costs, net | | (103) | | Financing costs, net | | (76) | |
Loss Before Income Taxes | | $ | (4,566) | | |
Income Before Income Taxes | | Income Before Income Taxes | | $ | 1,462 | |
| | | | | Total Assets(3) | | $ | 3,151 | | | $ | 2,366 | | | $ | 6,225 | | | $ | 1,574 | | | $ | 75 | | | $ | 13,391 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Six Months Ended June 30, 2022 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 1,692 | | | $ | 635 | | | $ | 1,253 | | | $ | — | | | $ | — | | | $ | 3,580 | |
Natural gas revenues | | 186 | | | 163 | | | 464 | | | — | | | — | | | 813 | |
Natural gas liquids revenues | | 6 | | | 28 | | | 421 | | | — | | | (3) | | | 452 | |
Oil, natural gas, and natural gas liquids production revenues | | 1,884 | | | 826 | | | 2,138 | | | — | | | (3) | | | 4,845 | |
Purchased oil and gas sales | | — | | | — | | | 866 | | | 5 | | | — | | | 871 | |
Midstream service affiliate revenues | | — | | | — | | | — | | | 16 | | | (16) | | | — | |
| | 1,884 | | | 826 | | | 3,004 | | | 21 | | | (19) | | | 5,716 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 262 | | | 214 | | | 228 | | | — | | | (1) | | | 703 | |
Gathering, processing, and transmission | | 10 | | | 24 | | | 154 | | | 5 | | | (18) | | | 175 | |
Purchased oil and gas costs | | — | | | — | | | 879 | | | — | | | — | | | 879 | |
Taxes other than income | | — | | | — | | | 145 | | | 3 | | | — | | | 148 | |
Exploration | | 27 | | | 7 | | | 5 | | | — | | | 59 | | | 98 | |
Depreciation, depletion, and amortization | | 188 | | | 116 | | | 263 | | | 2 | | | — | | | 569 | |
Asset retirement obligation accretion | | — | | | 40 | | | 17 | | | 1 | | | — | | | 58 | |
| | | | | | | | | | | | |
| | 487 | | | 401 | | | 1,691 | | | 11 | | | 40 | | | 2,630 | |
Operating Income (Loss)(2) | | $ | 1,397 | | | $ | 425 | | | $ | 1,313 | | | $ | 10 | | | $ | (59) | | | 3,086 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
Derivative instrument losses, net | | | | | | | | | | | | (94) | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 1,149 | |
Other, net | | | | | | | | | | | | 109 | |
General and administrative | | | | | | | | | | | | (245) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (17) | |
Financing costs, net | | | | | | | | | | | | (228) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 3,760 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Total Assets(3) | | $ | 3,107 | | | $ | 2,103 | | | $ | 7,156 | | | $ | — | | | $ | 558 | | | $ | 12,924 | |
(1)Includes a noncontrolling interest in Egyptrevenue from non-customers for the quarters and Altus.six months ended June 30, 2023 and 2022 of:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | | |
| | (In millions) |
Oil | | $ | 165 | | | $ | 302 | | | $ | 337 | | | $ | 552 | |
Natural gas | | 24 | | | 30 | | | 50 | | | 61 | |
Natural gas liquids | | — | | | 1 | | | — | | | 2 | |
(2)The operatingOperating income (loss)of U.S. and North Sea includes leasehold impairments of $3 million and $3 million, respectively, for the second quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $1 million and other asset$1 million, respectively, for the second quarter of 2022. Operating income of U.S. and North Sea includes leasehold impairments totaling $16of $5 million and $6 million, respectively, for the first six months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $4 million and $2 million, respectively, for the first quartersix months of 2021. The operating income (loss) of U.S., Egypt, and North Sea includes leasehold and other asset impairments totaling $4.0 billion, $511 million, and $7 million, respectively, for the first quarter of 2020.2022.
(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 Apache Corporation’sthe 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 Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.2022. On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly-owned subsidiary of APA Corporation and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The holding company structure modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.
Overview
APA is an independent energy company that exploresowns consolidated subsidiaries that explore for, develops,develop, and producesproduce 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 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. APA’sAs 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 iswas operated by Altus Midstream Company (Nasdaq: ALTM)(ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, APA believes energy underpins global progress, and operatesthe Company wants to be a midstream energy asset network inpart of the Permian Basin of West Texas.
APA’s mission isconversation and solution as society works to grow in an innovative, safe, environmentally responsible,meet growing global demand for reliable and profitable manneraffordable energy. APA strives to meet those challenges while creating value for the long-term benefit ofall its stakeholders. APA is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.
The global economy and the energy industry have been deeplycontinue to be impacted by the effects of the conflict in Ukraine and the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertaintypandemic. Uncertainties in the commodityglobal supply chain and financial markets, during 2020including the impact of inflation and 2021rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand.
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 ongoing exploration and appraisal 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 on a priority basis to debt reduction.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. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.
In the firstsecond quarter of 2021,2023, the Company reported net income attributable to common stock of $388$381 million, or $1.02$1.23 per diluted common share, compared to a lossnet income of $4.5 billion,$926 million, or $11.86$2.71 per commondiluted share, in the firstsecond quarter of 2020. The increase in net2022. Net income for the second quarter of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the prior-year period is primarily the result of significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic began to negatively affect economic activity and the oil markets. Included in the prior year reported net income was $4.5 billion of asset impairments recognized in the first quarter of 2020. In response to lower commodity prices, the Company materially reduced its upstream capital investment budget and drilling activity during the first quarter of 2020. Daily production decreased 18 percent from an average of 468 Mboe/d in the first quarter of 2020 to an average of 382 Mboe/d in the first quarter of 2021.period.
The Company generated $671 million$1.3 billion of cash from operating activities during the first threesix months of 2021, a 342023, 45 percent increase fromlower than the first threesix months of 20202022. APA’s lower operating cash flows for the first six months of 2023 were driven by higherlower commodity prices and associated revenues.revenues and the timing of working capital items. The Company endedrepurchased 5 million shares of its common stock for $188 million and paid $155 million in dividends to APA common stockholders during the first six 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 with $538 million of cash.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 second quarter of 2023, the Company has repurchased 72.4 million shares of the Company’s common stock. As of June 30, 2023, the Company had remaining authorization to repurchase up to 48 million shares under the Company’s share repurchase programs.
APA’s diverse asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. In response to prevailing weakness in Waha natural gas and NGL prices, the Company is deferring additional drilling and completion activity at Alpine High until prices can support sustainable returns that are competitive within APA’s global portfolio. The Company also announced the suspension of drilling activity in the North Sea with increasing cost and tax burdens impacting the competitiveness of these assets within the Company’s portfolio. Accordingly, the Company has reduced planned full-year upstream capital investment to approximately $1.9 billion.
Operational Highlights
Key operational highlights for the quarter include:
United States
•EquivalentDaily boe production from the Company’s U.S. assets accounted for 5553 percent of its total production during the firstsecond quarter of 2021. After halting all2023. The Company averaged five drilling and completion activity for most of 2020, the Company recently re-activated one rigrigs in the PermianU.S. during the quarter, including two rigs in the Southern Midland Basin and one rigthree rigs in the Austin Chalk. In addition, 22Delaware Basin, and drilled and brought online 21 operated wells in the quarter. Two-thirds of those wells came online in June, so the Permianfull impact will be realized in the third quarter. The Company’s core Midland Basin duringdevelopment program and recently acquired properties in the first quarter of 2021.Texas Delaware Basin continue to represent key growth areas for the U.S. assets.
International
•GrossIn Egypt, the Company averaged 17 drilling rigs and drilled 19 new productive wells during the second quarter of 2023. Second quarter 2023 gross equivalent production in the Company’s Egypt assets decreased 203 percent from the firstsecond quarter of 2020, given reduced drilling activity over the preceding year.2022, and net production remained relatively flat. The Company averaged five rigshas increased drilling and workover activity with a heavier focus on oil prospects and anticipates increases in Egypt, and six wells came online duringgross oil production volumes throughout the first quarterremainder of 2021. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage.the year as it maintains a steady operational cadence.
•The Company recently announced it has reached an agreementsuspended all new drilling activity in principle with Egypt’s Ministrythe North Sea during the second quarter of Petroleum2023. The Company will manage its base production and Mineral Resources (MOP) and the Egyptian General Petroleum Corporation (EGPC) in supportmaximize economic recovery of the MOP’s efforts to modernize the country’s petroleum sector. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust costits oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases. The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The new production sharing contract is subject to certain approvals within the Government of Egypt and ratification by Parliament.wells through well intervention activities.
•Suriname activity is focused on completing the Krabdagu appraisal program and scoping an oil hub project to develop the combined Sapakara and Krabdagu resource in Block 58. Testing has been completed at the Krabdagu-2 appraisal well, and data collection is ongoing at the Krabdagu-3 appraisal well. The North Sea averaged two rigs and completed one well duringsemi-submersible rig currently on location will be released upon completion of operations, as the first quarter of 2021. Extended operational downtimeCompany believes no additional appraisal or exploratory drilling is necessary in the Forties Field negatively impacted volumes in the quarter, and further impacts are expected in the second and third quarters of 2021 as a result of Forties pipeline downtime and platform maintenance turnarounds.
•In late 2020, the Company commenced drilling a fourth exploration wellKrabdagu area at the Keskesi prospect in Block 58 offshore Suriname. In January 2021, the Company and its partner Total S.A announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to Total S.A, with ongoing exploration and appraisal activities continuing to progress.this time.
Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Production Revenues
Revenue
The Company’s oil and gas production revenues and respective contribution to total revenues by country were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | | 2023 | | 2022 | | 2023 | | 2022 |
| | | 2021 | | 2020 | | | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution |
| | $ Value | | % Contribution | | $ Value | | % Contribution | | | | | | | | | | | | | | | | | |
| | | ($ in millions) | | | ($ in millions) |
Oil Revenues: | Oil Revenues: | | | Oil Revenues: | |
United States | United States | | $ | 348 | | | 35 | % | | $ | 428 | | | 41 | % | | United States | | $ | 512 | | | 38 | % | | $ | 654 | | | 35 | % | | $ | 998 | | | 36 | % | | $ | 1,253 | | | 35 | % |
Egypt(1) | Egypt(1) | | 402 | | | 41 | % | | 333 | | | 33 | % | | Egypt(1) | | 618 | | | 45 | % | | 902 | | | 48 | % | | 1,247 | | | 45 | % | | 1,692 | | | 47 | % |
North Sea | North Sea | | 241 | | | 24 | % | | 271 | | | 26 | % | | North Sea | | 235 | | | 17 | % | | 307 | | | 17 | % | | 517 | | | 19 | % | | 635 | | | 18 | % |
Total(1) | Total(1) | | $ | 991 | | | 100 | % | | $ | 1,032 | | | 100 | % | | Total(1) | | $ | 1,365 | | | 100 | % | | $ | 1,863 | | | 100 | % | | $ | 2,762 | | | 100 | % | | $ | 3,580 | | | 100 | % |
| Natural Gas Revenues: | Natural Gas Revenues: | | | Natural Gas Revenues: | |
United States | United States | | $ | 211 | | | 68 | % | | $ | 39 | | | 32 | % | | United States | | $ | 51 | | | 28 | % | | $ | 281 | | | 65 | % | | $ | 140 | | | 33 | % | | $ | 464 | | | 57 | % |
Egypt(1) | Egypt(1) | | 70 | | | 22 | % | | 65 | | | 53 | % | | Egypt(1) | | 90 | | | 50 | % | | 88 | | | 20 | % | | 183 | | | 43 | % | | 186 | | | 23 | % |
North Sea | North Sea | | 31 | | | 10 | % | | 19 | | | 15 | % | | North Sea | | 39 | | | 22 | % | | 64 | | | 15 | % | | 99 | | | 24 | % | | 163 | | | 20 | % |
Total(1) | Total(1) | | $ | 312 | | | 100 | % | | $ | 123 | | | 100 | % | | Total(1) | | $ | 180 | | | 100 | % | | $ | 433 | | | 100 | % | | $ | 422 | | | 100 | % | | $ | 813 | | | 100 | % |
| NGL Revenues: | NGL Revenues: | | | NGL Revenues: | |
United States | United States | | $ | 120 | | | 94 | % | | $ | 71 | | | 88 | % | | United States | | $ | 103 | | | 96 | % | | $ | 214 | | | 93 | % | | $ | 223 | | | 94 | % | | $ | 418 | | | 92 | % |
Egypt(1) | Egypt(1) | | 2 | | | 1 | % | | 3 | | | 4 | % | | Egypt(1) | | — | | | 0 | % | | 3 | | | 1 | % | | — | | | 0 | % | | 6 | | | 2 | % |
North Sea | North Sea | | 6 | | | 5 | % | | 7 | | | 8 | % | | North Sea | | 4 | | | 4 | % | | 12 | | | 6 | % | | 14 | | | 6 | % | | 28 | | | 6 | % |
Total(1) | Total(1) | | $ | 128 | | | 100 | % | | $ | 81 | | | 100 | % | | Total(1) | | $ | 107 | | | 100 | % | | $ | 229 | | | 100 | % | | $ | 237 | | | 100 | % | | $ | 452 | | | 100 | % |
| Oil and Gas Revenues: | Oil and Gas Revenues: | | | Oil and Gas Revenues: | |
United States | United States | | $ | 679 | | | 47 | % | | $ | 538 | | | 44 | % | | United States | | $ | 666 | | | 40 | % | | $ | 1,149 | | | 46 | % | | $ | 1,361 | | | 40 | % | | $ | 2,135 | | | 44 | % |
Egypt(1) | Egypt(1) | | 474 | | | 33 | % | | 401 | | | 32 | % | | Egypt(1) | | 708 | | | 43 | % | | 993 | | | 39 | % | | 1,430 | | | 42 | % | | 1,884 | | | 39 | % |
North Sea | North Sea | | 278 | | | 20 | % | | 297 | | | 24 | % | | North Sea | | 278 | | | 17 | % | | 383 | | | 15 | % | | 630 | | | 18 | % | | 826 | | | 17 | % |
Total(1) | Total(1) | | $ | 1,431 | | | 100 | % | | $ | 1,236 | | | 100 | % | | Total(1) | | $ | 1,652 | | | 100 | % | | $ | 2,525 | | | 100 | % | | $ | 3,421 | | | 100 | % | | $ | 4,845 | | | 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 March 31, | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | 2021 | | Increase (Decrease) | | 2020 | | | 2023 | | Increase (Decrease) | | 2022 | | 2023 | | Increase (Decrease) | | 2022 |
Oil Volume – b/d | | | | | | | | |
Oil Volume (b/d) | | Oil Volume (b/d) | | | | | | | | | | | | |
United States | United States | | 67,690 | | | (33) | % | | 101,614 | | | United States | | 75,993 | | | 17% | | 64,759 | | | 73,952 | | | 10% | | 67,184 | |
Egypt(1)(2) | Egypt(1)(2) | | 72,170 | | | (1) | % | | 73,178 | | | Egypt(1)(2) | | 87,790 | | | 3% | | 85,502 | | | 87,792 | | | 3% | | 85,261 | |
North Sea | North Sea | | 43,524 | | | (21) | % | | 55,262 | | | North Sea | | 35,048 | | | 8% | | 32,493 | | | 36,268 | | | 7% | | 33,860 | |
Total | Total | | 183,384 | | | (20) | % | | 230,054 | | | Total | | 198,831 | | | 9% | | 182,754 | | | 198,012 | | | 6% | | 186,305 | |
| Natural Gas Volume – Mcf/d | | | |
Natural Gas Volume (Mcf/d) | | Natural Gas Volume (Mcf/d) | |
United States | United States | | 507,517 | | | (15) | % | | 597,842 | | | United States | | 450,200 | | | (2)% | | 457,459 | | | 445,887 | | | (5)% | | 467,493 | |
Egypt(1)(2) | Egypt(1)(2) | | 278,149 | | | 9 | % | | 254,579 | | | Egypt(1)(2) | | 337,413 | | | (3)% | | 346,424 | | | 346,829 | | | (5)% | | 366,390 | |
North Sea | North Sea | | 49,840 | | | (26) | % | | 67,278 | | | North Sea | | 37,194 | | | (13)% | | 42,802 | | | 38,769 | | | (5)% | | 40,645 | |
Total | Total | | 835,506 | | | (9) | % | | 919,699 | | | Total | | 824,807 | | | (3)% | | 846,685 | | | 831,485 | | | (5)% | | 874,528 | |
| NGL Volume – b/d | | | |
NGL Volume (b/d) | | NGL Volume (b/d) | |
United States | United States | | 57,815 | | | (29) | % | | 81,381 | | | United States | | 61,760 | | | 4% | | 59,267 | | | 58,947 | | | (3)% | | 60,482 | |
Egypt(1)(2) | Egypt(1)(2) | | 583 | | | (36) | % | | 918 | | | Egypt(1)(2) | | — | | | NM | | 297 | | | — | | | NM | | 394 | |
North Sea | North Sea | | 1,368 | | | (36) | % | | 2,135 | | | North Sea | | 872 | | | (27)% | | 1,195 | | | 1,062 | | | (21)% | | 1,345 | |
Total | Total | | 59,766 | | | (29) | % | | 84,434 | | | Total | | 62,632 | | | 3% | | 60,759 | | | 60,009 | | | (4)% | | 62,221 | |
| BOE per day(3) | BOE per day(3) | | | BOE per day(3) | |
United States | United States | | 210,091 | | | (26) | % | | 282,636 | | | United States | | 212,786 | | | 6% | | 200,269 | | | 207,213 | | | 1% | | 205,582 | |
Egypt(1)(2) | Egypt(1)(2) | | 119,111 | | | 2 | % | | 116,525 | | | Egypt(1)(2) | | 144,026 | | | 0% | | 143,536 | | | 145,597 | | | (1)% | | 146,720 | |
North Sea(4) | North Sea(4) | | 53,199 | | | (22) | % | | 68,610 | | | North Sea(4) | | 42,118 | | | 3% | | 40,822 | | | 43,792 | | | 4% | | 41,979 | |
Total | Total | | 382,401 | | | (18) | % | | 467,771 | | | Total | | 398,930 | | | 4% | | 384,627 | | | 396,602 | | | 1% | | 394,281 | |
(1)Gross oil, natural gas, and NGL production in Egypt were as follows:
| | | For the Quarter Ended March 31, | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | 2021 | | 2020 | | | | 2023 | | 2022 | | 2023 | | 2022 |
Oil (b/d) | Oil (b/d) | | 135,320 | | | 183,627 | | | Oil (b/d) | | 140,652 | | | 141,432 | | | 140,708 | | | 137,934 | |
Natural Gas (Mcf/d) | Natural Gas (Mcf/d) | | 603,269 | | | 655,410 | | | Natural Gas (Mcf/d) | | 517,291 | | | 555,694 | | | 531,093 | | | 576,637 | |
NGL (b/d) | NGL (b/d) | | 897 | | | 1,782 | | | NGL (b/d) | | — | | | 464 | | | — | | | 599 | |
(2)Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
| | | For the Quarter Ended March 31, | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | 2021 | | 2020 | | | | 2023 | | 2022 | | 2023 | | 2022 |
Oil (b/d) | Oil (b/d) | | 24,088 | | | 24,598 | | | Oil (b/d) | | 29,298 | | | 28,516 | | | 29,296 | | | 28,423 | |
Natural Gas (Mcf/d) | Natural Gas (Mcf/d) | | 92,936 | | | 85,672 | | | Natural Gas (Mcf/d) | | 112,609 | | | 115,534 | | | 115,738 | | | 122,112 | |
NGL (b/d) | NGL (b/d) | | 194 | | | 306 | | | NGL (b/d) | | — | | | 99 | | | — | | | 131 | |
(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 first quartersecond quarters of 20212023 and 20202022 were 54,54440,099 boe/d and 73,27038,029 boe/d, respectively, and 43,347 boe/d and 40,833 boe/d for the first six months of 2023 and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.liftings.
NM — Not Meaningful
Pricing
The Company’s average selling prices by country were as follows:
| | | | For the Quarter Ended March 31, | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | 2021 | | Increase (Decrease) | | 2020 | | | 2023 | | Increase (Decrease) | | 2022 | | 2023 | | Increase (Decrease) | | 2022 |
Average Oil Price - Per barrel | | | | | | | | |
Average Oil Price – Per barrel | | Average Oil Price – Per barrel | | | | | | | | | | | | |
United States | United States | | $ | 57.16 | | | 23 | % | | $ | 46.32 | | | United States | | $ | 73.99 | | | (33)% | | $ | 110.98 | | | $ | 74.56 | | | (28)% | | $ | 103.05 | |
Egypt | Egypt | | 61.89 | | | 24 | % | | 49.97 | | | Egypt | | 77.39 | | | (33)% | | 115.97 | | | 78.48 | | | (28)% | | 109.65 | |
North Sea | North Sea | | 59.67 | | | 20 | % | | 49.66 | | | North Sea | | 79.27 | | | (30)% | | 113.77 | | | 80.51 | | | (25)% | | 107.47 | |
Total | Total | | 59.62 | | | 23 | % | | 48.31 | | | Total | | 76.38 | | | (33)% | | 113.79 | | | 77.37 | | | (28)% | | 106.87 | |
| Average Natural Gas Price - Per Mcf | | | |
Average Natural Gas Price – Per Mcf | | Average Natural Gas Price – Per Mcf | |
United States | United States | | $ | 4.61 | | | 559 | % | | $ | 0.70 | | | United States | | $ | 1.24 | | | (82)% | | $ | 6.75 | | | $ | 1.73 | | | (68)% | | $ | 5.48 | |
Egypt | Egypt | | 2.79 | | | (1) | % | | 2.83 | | | Egypt | | 2.95 | | | 6% | | 2.78 | | | 2.92 | | | 4% | | 2.80 | |
North Sea | North Sea | | 6.93 | | | 119 | % | | 3.17 | | | North Sea | | 11.29 | | | (38)% | | 18.15 | | | 14.47 | | | (41)% | | 24.72 | |
Total | Total | | 4.14 | | | 182 | % | | 1.47 | | | Total | | 2.39 | | | (58)% | | 5.65 | | | 2.81 | | | (46)% | | 5.16 | |
| Average NGL Price - Per barrel | | | |
Average NGL Price – Per barrel | | Average NGL Price – Per barrel | |
United States | United States | | $ | 22.99 | | | 140 | % | | $ | 9.59 | | | United States | | $ | 18.26 | | | (54)% | | $ | 39.79 | | | $ | 20.88 | | | (45)% | | $ | 38.20 | |
Egypt | Egypt | | 44.74 | | | 41 | % | | 31.70 | | | Egypt | | — | | | NM | | 75.14 | | | — | | | NM | | 76.80 | |
North Sea | North Sea | | 48.59 | | | 33 | % | | 36.53 | | | North Sea | | 39.24 | | | (45)% | | 71.71 | | | 49.52 | | | (32)% | | 73.29 | |
Total | Total | | 23.79 | | | 126 | % | | 10.51 | | | Total | | 18.69 | | | (54)% | | 40.97 | | | 21.62 | | | (45)% | | 39.63 | |
NM — Not Meaningful
First-Quarter 2021Second-Quarter 2023 compared to First-Quarter 2020Second-Quarter 2022
Crude Oil Crude oil revenues for the firstsecond quarter of 20212023 totaled $991 million,$1.4 billion, a $41$498 million decrease from the comparative 20202022 quarter. A 2333 percent increasedecrease in average realized prices increased first-quarter 2021decreased second-quarter 2023 oil revenues by $241$613 million compared to the prior-year quarter, while 209 percent lowerhigher average daily production decreasedincreased revenues by $282$115 million. Crude oil revenues accounted for 6983 percent of total oil and gas production revenues and 4850 percent of worldwide production in the firstsecond quarter of 2021. 2023. Crude oil prices realized in the second quarter of 2023 averaged $76.38 per barrel, compared with $113.79 per barrel in the comparative prior-year quarter.
The Company’s worldwide oil production decreased 47increased 16.1 Mb/d to 183.4198.8 Mb/d induring the firstsecond quarter of 20212023 from the comparative prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity, and recompletions, partially offset by natural production decline across all countries, as well as extended operational downtime in the North Sea and weather disruptions in the U.S. following Winter Storm Uri in Texas in February 2021. Crude oil prices realized in the first quarter of 2021 averaged $59.62 per barrel, compared to $48.31 per barrel in the comparative prior-year quarter.assets.
Natural Gas Gas revenues for the firstsecond quarter of 20212023 totaled $312$180 million, a $189$253 million increasedecrease from the comparative 20202022 quarter. A 18258 percent increasedecrease in average realized prices increased first-quarter 2021decreased second-quarter 2023 natural gas revenues by $224$249 million compared to the prior-year quarter, while 93 percent lower average daily production decreased revenues by $35$4 million. Natural gas revenues accounted for 2211 percent of total oil and gas production revenues and 3634 percent of worldwide production during the firstsecond quarter of 2021. Gas prices in the first quarter of 2021 reflect extreme price volatility during the month of February due to the Texas freeze event.2023. The Company’s worldwide natural gas production decreased 8421.9 MMcf/d to 836824.8 MMcf/d induring the firstsecond quarter of 20212023 from the comparative prior-year period, primarily a result of natural production decline across all countriesassets and impactssale of winter stormsnon-core assets in the U.S., partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.
NGL NGL revenues for the firstsecond quarter of 20212023 totaled $128$107 million, a $47$122 million increasedecrease from the comparative 20202022 quarter. A 12654 percent increasedecrease in average realized prices increased first-quarter 2021decreased second-quarter 2023 NGL revenues by $102$125 million compared to the prior-year quarter, while 293 percent lowerhigher average daily production decreasedincreased revenues by $55$3 million. NGL revenues accounted for 96 percent of total oil and gas production revenues and 16 percent of worldwide production during the firstsecond quarter of 2021.2023. The Company’s worldwide NGL production decreased 24.7increased 1.9 Mb/d to 59.862.6 Mb/d induring the firstsecond quarter of 20212023 from the comparative prior-year period, primarily a result of production declineincreased drilling activity, recompletions, and property acquisitions in the U.S.
Altus Midstream Revenues
Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $32 million and $41 million during the first quarter of 2021 and 2020, respectively. These affiliated revenues are eliminated upon consolidation. The decrease compared to the prior-year period was primarily driven, partially offset by lower throughput of natural gas volumes from the Company.production decline.
Year-to-Date 2023 compared to Year-to-Date 2022
Crude Oil Crude oil revenues for the first six months of 2023 totaled $2.8 billion, an $818 million decrease from the comparative 2022 period. A 28 percent decrease in average realized prices decreased oil revenues for the 2023 period by $988 million compared to the prior-year period, while 6 percent higher average daily production increased revenues by $170 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first six months of 2023. Crude oil prices realized during the first six months of 2023 averaged $77.37 per barrel, compared to $106.87 per barrel in the comparative prior-year period.
The Company’s worldwide oil production increased 11.7 Mb/d to 198.0 Mb/d in the first six months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity, and recompletions, partially offset by natural production decline across all assets.
Natural Gas Gas revenues for the first six months of 2023 totaled $422 million, a $391 million decrease from the comparative 2022 period. A 46 percent decrease in average realized prices decreased natural gas revenues for the 2023 period by $371 million compared to the prior-year period, while 5 percent lower average daily production decreased revenues by $20 million compared to the prior-year period. Natural gas revenues accounted for 12 percent of total oil and gas production revenues and 35 percent of worldwide production for the first six months of 2023. The Company’s worldwide natural gas production decreased 43.0 MMcf/d to 831.5 MMcf/d in the first six months of 2023 compared to the prior-year period, primarily a result of natural production decline across all assets and sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.
NGL NGL revenues for the first six months of 2023 totaled $237 million, a $215 million decrease from the comparative 2022 period. A 45 percent decrease in average realized prices decreased NGL revenues for the 2023 period by $205 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $10 million compared to the prior-year period. NGL revenues accounted for 7 percent of total oil and gas production revenues and 15 percent of worldwide production for the first six months of 2023. The Company’s worldwide NGL production decreased 2.2 Mb/d to 60 Mb/d in the first six months of 2023 compared to the prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.
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, whichobligations. Sales related to these purchased volumes totaled $440$144 million and $108$522 million during the second quarters of 2023 and 2022, respectively, and $383 million and $871 million during the first quarterssix months of 20212023 and 2020,2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $494$131 million and $86$528 million during the second quarters of 2023 and 2022, respectively, and $347 million and $879 million during the first quarterssix months of 20212023 and 2020,2022, respectively. When compared to the prior-year period, the first-quarter 2021 grossGross purchased oil and gas sales values were lower in the second quarter and the associated net loss were exacerbated by extreme price volatilityfirst six months of 2023, primarily due to lower average natural gas prices during the month of February due to Winter Storm Uri in Texas.2023 periods.
Operating Expenses
The Company’s operating expenses were as follows:
| | | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | | 2023 | | 2022 | | 2023 | | 2022 |
| | | 2021 | | 2020 | | | | | | | | | |
| | | (In millions) | | | (In millions) |
Lease operating expenses | Lease operating expenses | | $ | 264 | | | $ | 335 | | | Lease operating expenses | | $ | 361 | | | $ | 359 | | | $ | 682 | | | $ | 703 | |
Gathering, processing, and transmission | Gathering, processing, and transmission | | 58 | | | 71 | | | Gathering, processing, and transmission | | 78 | | | 94 | | | 156 | | | 175 | |
Purchased oil and gas costs | Purchased oil and gas costs | | 494 | | | 86 | | | Purchased oil and gas costs | | 131 | | | 528 | | | 347 | | | 879 | |
Taxes other than income | Taxes other than income | | 44 | | | 33 | | | Taxes other than income | | 50 | | | 78 | | | 102 | | | 148 | |
Exploration | Exploration | | 49 | | | 57 | | | Exploration | | 43 | | | 56 | | | 95 | | | 98 | |
General and administrative | General and administrative | | 83 | | | 68 | | | General and administrative | | 72 | | | 89 | | | 137 | | | 245 | |
Transaction, reorganization, and separation | Transaction, reorganization, and separation | | — | | | 27 | | | Transaction, reorganization, and separation | | 2 | | | 3 | | | 6 | | | 17 | |
Depreciation, depletion, and amortization: | Depreciation, depletion, and amortization: | | | Depreciation, depletion, and amortization: | |
Oil and gas property and equipment | Oil and gas property and equipment | | 312 | | | 531 | | | Oil and gas property and equipment | | 354 | | | 269 | | | 679 | | | 547 | |
Gathering, processing, and transmission assets | Gathering, processing, and transmission assets | | 19 | | | 20 | | | Gathering, processing, and transmission assets | | 1 | | | 1 | | | 3 | | | 6 | |
Other assets | Other assets | | 11 | | | 15 | | | Other assets | | 12 | | | 8 | | | 17 | | | 16 | |
Asset retirement obligation accretion | Asset retirement obligation accretion | | 28 | | | 27 | | | Asset retirement obligation accretion | | 29 | | | 29 | | | 57 | | | 58 | |
Impairments | Impairments | | — | | | 4,472 | | | Impairments | | 46 | | | — | | | 46 | | | — | |
Financing costs, net | Financing costs, net | | 110 | | | 103 | | | Financing costs, net | | 82 | | | 76 | | | 154 | | | 228 | |
Total Operating Expenses | | Total Operating Expenses | | $ | 1,261 | | | $ | 1,590 | | | $ | 2,481 | | | $ | 3,120 | |
Lease Operating Expenses (LOE)
LOE remained essentially flat in the second quarter of 2023 when compared to the second quarter of 2022 and decreased $71$21 million fromin the first quartersix months of 2020.2023 when compared to the first six months of 2022. On a per-unit basis, LOE decreased 23 percent forand 4 percent in the second quarter and the first quartersix months of 2021 compared to2023, respectively, from the comparative prior-year period. The decrease in absolute dollar costs was primarily driven by reducedthe impact from changes in foreign currency exchange rates against the US dollar, decreased workover activity, primarily in the North Sea, and mark-to-market adjustments for cash-based stock compensation expense resulting from changes in the Company’s stock price. These decreases were offset by overall higher labor costs the Company’s organizational redesign,and chemical and other cost cutting efforts.operating costs trending with global inflation.
Gathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
| | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | For the Quarter Ended March 31, | | | 2023 | | 2022 | | 2023 | | 2022 |
| | 2021 | | 2020 | | | | | | | | | |
| | (In millions) | | (In millions) |
Third-party processing and transmission costs | Third-party processing and transmission costs | | $ | 51 | | | $ | 60 | | | Third-party processing and transmission costs | | $ | 49 | | | $ | 68 | | | $ | 101 | | | $ | 134 | |
Midstream service affiliate costs | | 31 | | | 40 | | | |
Midstream service costs – ALTM | | Midstream service costs – ALTM | | — | | | — | | | — | | | 18 | |
Midstream service costs – Kinetik | | Midstream service costs – Kinetik | | 29 | | | 26 | | | 55 | | | 36 | |
Upstream processing and transmission costs | Upstream processing and transmission costs | | 82 | | | 100 | | | Upstream processing and transmission costs | | 78 | | | 94 | | | 156 | | | 188 | |
Midstream operating expenses | Midstream operating expenses | | 7 | | | 11 | | | Midstream operating expenses | | — | | | — | | | — | | | 5 | |
Intersegment eliminations | Intersegment eliminations | | (31) | | | (40) | | | Intersegment eliminations | | — | | | — | | | — | | | (18) | |
Total Gathering, processing, and transmission | Total Gathering, processing, and transmission | | $ | 58 | | | $ | 71 | | | Total Gathering, processing, and transmission | | $ | 78 | | | $ | 94 | | | $ | 156 | | | $ | 175 | |
GPT costs decreased $13$16 million and $19 million in the second quarter and the first six months of 2023, respectively, from the first quarter 2020. Third-partycomparative 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 $9$16 million compared toand $32 million in the second quarter and the first quartersix months of 2020,2023, respectively, from the comparative prior-year period, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $9 millionnatural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in the first quartersix months of 2020, primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, decreased $4 million compared2022, prior to the first quarterBCP 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 2020, drivenAltus on February 22, 2022, these midstream services continue to be provided by increased operational efficiency and continued cost cutting efforts.Kinetik Holdings Inc. (Kinetik) but are no longer eliminated.
Purchased Oil and Gas Costs
Purchased oil and gas costs totaled $494 million and $86 million during the first quarters of 2021 and 2020, respectively. Purchased oil and gas costs were offset by associated purchase sales of $440 million and $108 million during the first quarters of 2021 and 2020, respectively, as further discussed above.
Taxes Other Than Income
Taxes other than income increased $11decreased $28 million and $46 million from the second quarter and the first quartersix months of 2020,2022, respectively, primarily from higherlower severance taxes driven by higherlower commodity prices as compared to the prior-year period.periods.
Exploration Expenses
The Company’s exploration expenses were as follows:
| | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | For the Quarter Ended March 31, | | | 2023 | | 2022 | | 2023 | | 2022 |
| | 2021 | | 2020 | | | | | | | | | |
| | (In millions) | | (In millions) |
Unproved leasehold impairments | Unproved leasehold impairments | | $ | 18 | | | $ | 19 | | | Unproved leasehold impairments | | $ | 6 | | | $ | 2 | | | $ | 11 | | | $ | 6 | |
Dry hole expense | Dry hole expense | | 19 | | | 24 | | | Dry hole expense | | 23 | | | 36 | | | 53 | | | 41 | |
Geological and geophysical expense | Geological and geophysical expense | | 4 | | | 3 | | | Geological and geophysical expense | | 1 | | | 3 | | | 2 | | | 18 | |
Exploration overhead and other | Exploration overhead and other | | 8 | | | 11 | | | Exploration overhead and other | | 13 | | | 15 | | | 29 | | | 33 | |
Total Exploration | Total Exploration | | $ | 49 | | | $ | 57 | | | Total Exploration | | $ | 43 | | | $ | 56 | | | $ | 95 | | | $ | 98 | |
Exploration expenses decreased $8$13 million from the second quarter of 2022, primarily the result of higher dry hole expense in Suriname during the second quarter of 2022. Exploration expenses decreased $3 million from the first quartersix months of 2020,2022, primarily the result of a $5 millionlower geological and $3 million decrease in dry holegeophysical expense and exploration overhead respectively, drivenduring the second quarter of 2023, partially offset by a decrease inhigher dry hole expense from increased Egypt exploration activity. The Company drilled 3 and 6 gross exploration wells in the first quarters of 2021 and 2020, respectively.activity during 2023.
General and Administrative (G&A) Expenses
G&A expenses increased $15decreased $17 million fromand $108 million compared to the second quarter and the first six months of 2022, respectively. The decrease in expenses for the second quarter and the first six months of 2020,2023 compared to the prior-year period was primarily related to higherdriven by lower cash-based stock compensation expense resulting from an increasechanges in the Company’s stock price. This increase was partially offset by Company-wide overhead reductions associated with the Company’s organizational redesign efforts in late 2019 and 2020.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs remained essentially flat compared to the second quarter of 2022 and decreased $27$11 million compared to the first six months of 2022. The decrease in costs during the first six months of 2023 compared to the prior-year period was primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2020, driven by costs associated with the Company’s reorganization efforts incurred in the prior year.
In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed in 2020.2022.
Depreciation, Depletion, and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas properties decreased $219increased $85 million and $132 million from the second quarter and the first quartersix months of 2020.2022, respectively. The Company’s DD&A rate on its oil and gas property DD&A rate decreased $3.32properties increased $2.09 per boe and $1.79 per boe from the second quarter and the first quartersix months of 2020. The decrease was2022, respectively, driven by lower production volumesgeneral cost inflation. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and lower asset property balances associated with proved property impairments recordedacquisitions in the first quarter of 2020. DD&A expense onU.S. over the Company’s GPT assets decreased $1 million from the first quarter of 2020.past year.
Impairments
TheDuring the three and six months ended June 30, 2023, the Company recorded no asset$46 million of impairments in connection with fair value assessmentsvaluations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the first quarter of 2021. During the first quarter of 2020, the Company recorded asset impairments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S., Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $18 million for inventory and other miscellaneous assets, including charges for the early termination of drilling rig leases.Sea.
Financing Costs, Net
The Company’s Financing costs were as follows:
| | | | | | | | | | | | | | | | | For the Quarter Ended June 30, | | For the Six Months Ended June 30, |
| | | For the Quarter Ended March 31, | | | | 2023 | | 2022 | | 2023 | | 2022 |
| | | 2021 | | 2020 | | | | | | | | | |
| | | (In millions) | | | (In millions) |
Interest expense | Interest expense | | $ | 112 | | | $ | 107 | | | Interest expense | | $ | 89 | | | $ | 79 | | | $ | 177 | | | $ | 169 | |
Amortization of debt issuance costs | Amortization of debt issuance costs | | 2 | | | 2 | | | Amortization of debt issuance costs | | 1 | | | 5 | | | 2 | | | 7 | |
Capitalized interest | Capitalized interest | | (2) | | | (4) | | | Capitalized interest | | (5) | | | (5) | | | (11) | | | (8) | |
| (Gain) loss on extinguishment of debt | | (Gain) loss on extinguishment of debt | | — | | | — | | | (9) | | | 67 | |
Interest income | Interest income | | (2) | | | (2) | | | Interest income | | (3) | | | (3) | | | (5) | | | (7) | |
Total Financing costs, net | Total Financing costs, net | | $ | 110 | | | $ | 103 | | | Total Financing costs, net | | $ | 82 | | | $ | 76 | | | $ | 154 | | | $ | 228 | |
Net financing costs increased $7$6 million and decreased $74 million from the second quarter and the first six months of 2022, respectively. The increase in costs during the second quarter of 2020,2023 was primarily a result of a $5 million increase in interest expense on a higher letter ofoutstanding credit balancefacility borrowings compared to the prior-year period. The decrease in costs during the first six months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first six months of 2022 and gains on extinguishment of debt in the first six months of 2023.
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 firstsecond quarter of 2021,2023, 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 firstsecond quarter of 2020,2022, the Company’s effective income tax rate was primarily impacted by oila 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, and gas impairments, a goodwill impairment, and an increasedecrease 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 recordedis 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 within 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 isand its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various statestates and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.
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 both in the short-term and the long-term, are impacted by highly volatile oil and natural gascommodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact APA’sthe Company’s revenues, earnings, and cash flows. These changes potentially impact APA’sthe Company’s liquidity if costs do not trend with changessustained 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.
APA’sThe 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 APA’sthe Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
The Company’s capital investment for the first quarter of 2021 was belowCompany expects its planned budget announced earlier in 2021, but the Company remains on-track for its full year guidance andfull-year 2023 estimated upstream capital program of $1.1 billion. The program consists ofinvestment to be approximately $900 million$1.9 billion and remains committed to its capital return framework established in 2021 for development activities across its portfolioequity holders to participate more directly and approximately $200 million for exploration, predominantlymaterially in Suriname.cash returns through dividends and share repurchases.
The Company believes theits available liquidity and capital resource alternatives, available to the Company, 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 APA’sthe Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and any amountamounts that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.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 of Apache Corporation for the fiscal year ended December 31, 2020.2022.
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.presented:
| | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, |
| | 2021 | | 2020 |
| | (In millions) |
Sources of Cash and Cash Equivalents: | | | | |
Net cash provided by operating activities | | $ | 671 | | | $ | 502 | |
Proceeds from Apache credit facility, net | | — | | | 250 | |
Proceeds from Altus credit facility, net | | 33 | | | 72 | |
Proceeds from asset divestitures | | 3 | | | 126 | |
| | | | |
| | | | |
Total Sources of Cash and Cash Equivalents | | 707 | | | 950 | |
Uses of Cash and Cash Equivalents: | | | | |
Additions to upstream oil and gas property(1) | | $ | 253 | | | $ | 511 | |
Additions to Altus gathering, processing, and transmission facilities(1) | | 1 | | | 19 | |
Leasehold and property acquisitions | | 2 | | | 1 | |
Contributions to Altus equity method interests | | 21 | | | 83 | |
| | | | |
Payments on Apache credit facility, net | | 85 | | | — | |
Payments on fixed-rate debt | | 6 | | | — | |
Dividends paid | | 9 | | | 94 | |
Distributions to noncontrolling interest - Egypt | | 40 | | | 32 | |
Distributions to Altus Preferred Unit limited partners | | 11 | | | — | |
Other | | 3 | | | 29 | |
Total Uses of Cash and Cash Equivalents | | 431 | | | 769 | |
Increase in cash and cash equivalents | | $ | 276 | | | $ | 181 | |
(1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Quarterly Report on Form 10-Q, which include accruals. | | | | | | | | | | | | | | |
| | For the Six Months Ended June 30, |
| | 2023 | | 2022 |
| | | | |
| | (In millions) |
Sources of Cash and Cash Equivalents: | | | | |
Net cash provided by operating activities | | $ | 1,335 | | | $ | 2,426 | |
Proceeds from revolving credit facilities, net | | 196 | | | — | |
Proceeds from asset divestitures | | 28 | | | 751 | |
Proceeds from sale of Kinetik shares | | — | | | 224 | |
| | | | |
| | | | |
Total Sources of Cash and Cash Equivalents | | 1,559 | | | 3,401 | |
Uses of Cash and Cash Equivalents: | | | | |
Additions to upstream oil and gas property | | $ | 1,119 | | | $ | 741 | |
| | | | |
Leasehold and property acquisitions | | 10 | | | 26 | |
Payments on revolving credit facilities, net | | — | | | 267 | |
Payments on Apache fixed-rate debt | | 65 | | | 1,370 | |
Dividends paid to APA common stockholders | | 155 | | | 86 | |
Distributions to noncontrolling interest – Egypt | | 100 | | | 159 | |
| | | | |
Treasury stock activity, net | | 188 | | | 552 | |
Deconsolidation of Altus cash and cash equivalents | | — | | | 143 | |
Other, net | | 25 | | | 77 | |
Total Uses of Cash and Cash Equivalents | | 1,662 | | | 3,421 | |
Decrease in Cash and Cash Equivalents | | $ | (103) | | | $ | (20) | |
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 crude oil and natural gascommodity 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 increased $169 millionduring the first six months of 2023 totaled $1.3 billion, down $1.1 billion from the first quartersix months of 2020,2022, primarily due to higherthe result of significantly lower commodity prices.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 ApacheRevolving Credit Facility,Facilities, NetDuring As of June 30, 2023, outstanding borrowings under the first three monthsCompany’s U.S. dollar denominated syndicated credit facility were $762 million, an increase of 2020, Apache borrowed $250$196 million under its revolving credit facility.
Proceeds from Altus Credit Facility, Net The initial construction of Altus’ gathering and processing assets and the exercise of its pipeline options for its equity interests in the equity method interest pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first three months of 2021 and 2020, Altus Midstream LP borrowed $33 million and $72 million, respectively, under its revolving credit facility. With the midstream infrastructure complete and all of the equity method interest pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and planned dividend program during 2021.since December 31, 2022.
Proceeds from Asset Divestitures The Company recordedreceived $28 million and $751 million in proceeds from the divestiture of certain non-core asset divestitures of $3 million and $126 millionassets during the first threesix months of 20212023 and 2020,2022, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first six 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 $253 million$1.1 billion and $511$741 million during the first threesix months of 20212023 and 2020,2022, respectively. The decreaseincrease in capital investment is reflective of the increase in the Company’s reduced capital program to align with anticipated operating cash flows.that has gradually increased over the past year. The Company operated an average of 9 drilling rigs and 21approximately 24 drilling rigs during the first quartersix months of 2021 and 2020, respectively.
Additions2023, compared to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $1 million and $19 millionan average of approximately 19 drilling rigs during the first threesix months of 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for the remainder of 2021 to be minimal.2022.
Leasehold and Property Acquisitions TheDuring the first six months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $2$10 million and $1$26 million, during the first three months of 2021 and 2020, respectively.
Contributions to Altus Equity Method Interests Altus made contributions of $21 million and $83 million during the first three months of 2021 and 2020, respectively, for equity interests in the equity method interest pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.Payments Apache Credit Facility During the first three months of 2021, Apache made payments of $85 million on its revolving credit facility borrowings.
Payments on Apache Fixed-Rate Debt During the first threesix months of 2021,ended June 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $7$74 million for an aggregate purchase price of $6$65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $1$10 million. NoThe Company recognized a $9 million gain or loss was recognized on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
During the six months ended June 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 six months ended June 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 intendswill continue to reduce debt outstanding under its indentures from time to time.
Dividends Paid to APA Common Stockholders The Company paid common stock dividends of $9$155 million and $94$86 million during the first threesix months of 20212023 and 2020, respectively. In2022, respectively, for dividends on its common stock. During the firstthird quarter of 2020,2022, the Company’s Board of Directors approved a reduction in the Company’san increase to its quarterly dividend per share from $0.125 to $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.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 made cash distributions totaling $40paid $100 million and $32$159 million to Sinopec during the first threesix months of 20212023 and 2020, respectively.2022, respectively, in cash distributions to Sinopec.
Distributions to Altus Preferred Units limited partnersTreasury Stock Activity, net Altus Midstream LP paid cash distributions of $11 million to its limited partners holding Preferred Units forIn the first threesix months of 2021. No cash distributions were made during2023, the Company repurchased 5 million shares at an average price of $37.53 per share totaling $188 million, and as of June 30, 2023, the Company had remaining authorization to repurchase 48 million shares. In the first threesix months of 2020. For more information regarding2022, the Preferred Units, refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part I, Item 1Company repurchased 14.2 million shares at an average price of this Quarterly Report on Form 10-Q.$38.79 per share totaling $552 million.
Liquidity
The following table presents a summary of the Company’s key financial indicators:
| | | | | | | | | | | | | | |
| | March 31, 2021 | | December 31, 2020 |
| | (In millions) |
Cash and cash equivalents | | $ | 538 | | | $ | 262 | |
Total debt - Apache | | 8,058 | | | 8,148 | |
Total debt - Altus | | 657 | | | 624 | |
Total deficit | | (261) | | | (645) | |
Available committed borrowing capacity - Apache | | 3,125 | | | 2,944 | |
Available committed borrowing capacity - Altus | | 141 | | | 176 | |
| | | | | | | | | | | | | | |
| | June 30, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Cash and cash equivalents | | $ | 142 | | | $ | 245 | |
Total debt – APA and Apache | | 5,576 | | | 5,453 | |
Total equity | | 1,696 | | | 1,345 | |
Available committed borrowing capacity under syndicated credit facilities | | 2,194 | | | 2,238 | |
Cash and Cash Equivalents As of March 31, 2021,June 30, 2023, the Company had $538$142 million in cash and cash equivalents, of which approximately $51 million was held by Altus.equivalents. The majority of the Company’s cash is invested in highly liquid, investment gradeinvestment-grade instruments with maturities of three months or less at the time of purchase.
Debt As of March 31, 2021,June 30, 2023, the Company had $5.6 billion in total debt outstanding, of $8.7 billion, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of March 31, 2021, the Company’sJune 30, 2023, current debt outstanding included $2 million of finance lease obligations of $2 million.obligations.
Committed Credit Facilities In March 2018, ApacheOn April 29, 2022, the Company entered into atwo 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 totaling $4.0 billion. In March 2019, the term of this facility was extended by one yearUS$1.8 billion (including a letter of credit subfacility of up to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exerciseUS$750 million, of an extension option. Apache canwhich US$150 million currently is committed). The Company may increase commitments up to $5.0an 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, includeswith 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 letterNew 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 subfacility ofthen 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 $3.0 billion,an aggregate principal amount of which $2.08 billion was committed asUS$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of March 31, 2021. The facilityindebtedness under senior notes and debentures outstanding under Apache’s existing indentures is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.less than US$1.0 billion.
As of March 31, 2021,June 30, 2023, there were $65$762 million of borrowings under the USD Agreement and an aggregate £573 million and $20£590 million in letters of credit outstanding under this facility.the GBP Agreement. As of June 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2020,2022, there were $150$566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £633 million and $40£652 million in letters of credit outstanding under this facility.the GBP Agreement. The outstanding 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.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of March 31, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.
Apache and Altus Midstream LP were in compliance with the terms of their respective credit facilities as of March 31, 2021.
Uncommitted Credit Facilities Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2021June 30, 2023 and December 31, 2020,2022, there were no outstanding borrowings under these facilities. As of June 30, 2023 there were £185 million and £34$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.
Commercial Paper Program Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in Apache’s credit ratings during 2020, the Company does not expect that Apache’s commercial paper program will be cost competitive with its other financing alternatives and does not anticipate that Apache will use it under such circumstances. As of March 31, 2021 and December 31, 2020, no commercial paper was outstanding.
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 as described inthat 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 Apache Corporation’sAPA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.2022. There have been no material changes to the contractual obligations described therein.
Potential Asset RetirementDecommissioning Obligations on Sold Properties
The Company hasCompany’s subsidiaries have potential exposure to future obligations related to divested properties. ApacheThe 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 the Company’ssuch GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APAAPA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, APAsuch subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
In 2013, the CompanyApache sold its GOM Shelf operations and properties (Legacyand its GOM Assets)operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the CompanyApache received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date.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 liabilities,obligations, Fieldwood posted letters of credit in favor of the CompanyApache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a trust account (Trust A),beneficiary and which iswere funded by a 10 percenttwo net profits interestinterests (NPIs) depending on future oil prices and of which the Company is the beneficiary.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 the CompanyApache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit.Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, the CompanyApache holds two bonds (Bonds) and the remainingfive Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Legacy GOM Assets as and when such abandonment and decommissioning obligations areApache is required to be performedperform 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. Fieldwood has submitted aOn 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 of reorganization, andbecame effective. Pursuant to the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan, would separate the Legacy GOM Assets were separated into a standalone company, andwhich 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 forto fund 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 AROs. IfBureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the proceedsdecommissioning obligations that it is currently obligated to perform on certain of production are insufficient forthe 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 AROs, thennotices to BSEE in the Company expectsfuture and that it may be required by the relevant governmental authoritiesreceive additional orders from BSEE requiring it to perform such AROs,decommission other Legacy GOM Assets.
As of June 30, 2023, Apache has incurred $464 million in which casedecommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will applynot, 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 $276 million had been reimbursed from Trust A as of June 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 reimbursement from the Bonds remainingand the Letters of Credit until all such funds and Trust A to pay for the AROs.securities are fully utilized. In addition, after such sources have been exhausted, the CompanyApache 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. Assets.
If the foregoingcombination 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 CompanyStandby Loan Agreement, then Apache may be forced to effectively use its available cash to coverfund the deficit.
As of June 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 $922 million to $1.1 billion on an undiscounted basis. Management does not believe any additionalspecific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $922 million as of June 30, 2023, representing the estimated costs of decommissioning it incursmay be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $472 million is reflected under the caption “Decommissioning contingency for performingsold Gulf of Mexico properties,” and $450 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of June 30, 2023, the Company has also recorded a $507 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $57 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 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 AROs.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. These factors have only been heightened as the result of continuing negative demand implications of the COVID-19 pandemic became more apparent. The Company continually monitors its market risk exposure, including the impactas oil and developments related to the COVID-19 pandemic, which introduced significant volatilitygas supply and demand are impacted by uncertainties in the commodity and financial markets subsequent toassociated with the year ended December 31, 2019.conflict in Ukraine, 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 increased 23decreased 33 percent from $48.31$113.79 per barrel to $59.62$76.38 per barrel during the first quartersecond quarters of 20202022 and 2021,2023, respectively. The Company’s average natural gas price realizations increased 182decreased 58 percent from $1.47$5.65 per Mcf to $4.14$2.39 per Mcf during the firstsecond quarters of 20202022 and 2021,2023, respectively. The Company’s average NGL price realizations increased 126decreased 54 percent from $10.51$40.97 per barrel to $23.79$18.69 per barrel during the first quartersecond quarters of 20202022 and 2021,2023, respectively. Based on average daily production for the firstsecond quarter of 2021,2023, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $17$18 million, a $0.10 per Mcf change in the weighted average realized price of 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 $5$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 March 31, 2021,June 30, 2023, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $14$36 million. A 10 percent increasechange in natural gas prices would decreasebe immaterial to the asset by approximately $1 million, while a 10 percent decrease in prices would increase the asset by approximately $1 million. As of March 31, 2021, the Company had open oil derivatives not designated as cash flow hedges in an asset position with a fair value of $24 million. A 10 percent increase in oil prices would move the commodity derivatives, to a liability position of $85 million, while a 10 percent decrease in prices would increase the asset to approximately $133 million. These fair value changes assumeassuming volatility based on prevailing market parameters at March 31, 2021.as of June 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
At March 31, 2021,As of June 30, 2023, the Company had $4.8 billion, net, in outstanding notes and debentures, totaled $8.0 billion, net, all of which was fixed-rate debt, with a weighted average interest rate of 4.985.34 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 the indentures,its syndicated credit facilities, and commercial paper program.facilities. As of March 31, 2021,June 30, 2023, the Company’sCompany had approximately $142 million in cash and cash equivalents, totaled approximately $538 million, approximately 4783 percent of which was invested in money market funds and short-term investments with major financial institutions. As of March 31, 2021, Apache Corporation and Altus Midstream LP hadJune 30, 2023, there were $762 million of borrowings outstanding borrowings of $65 million and $657 million, respectively, under their respectivethe Company’s syndicated revolving credit facilities. A changeChanges in the interest rate applicable to short-term investments and credit facility borrowings wouldare 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, andwhile the majority of costs incurred are paid in British pounds. InThe Company’s Egypt substantially all oil and gas production is sold under U.S. dollar contracts, and the majority of the 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. CurrencyForeign 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. A foreignForeign currency net gain or loss of $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of March 31, 2021.June 30, 2023.
The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. The Company had no outstanding foreign exchange derivative contracts as of March 31, 2021.
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 March 31, 2021,June 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 ourits disclosure controls, including compliance with various laws and regulations that apply to ourits 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 March 31, 2021June 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 Apache Corporation’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 20202022 and Note 12—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
Except as set forth herein, thereThere have been no material changes to the risk factors disclosed underin Part I, Item 1A—Risk Factors of Apache Corporation’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.2022.
Given the nature of their respective businesses,its business, Apache Corporation and Altus Midstream Company may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the applicable disclosures in Apache Corporation’s Quarterly ReportReports on Form 10-Q for the quarterquarterly periods ended March 31, 20212023 and Altus Midstream Company’sJune 30, 2023 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2021.
RISKS RELATED TO THE COMPANY’S HOLDING COMPANY STRUCTURE
The Company is dependent on the operations and funds of its subsidiaries, including Apache.
The Company has no business operations of its own, and the Company’s only significant assets are the outstanding equity interests of its subsidiaries, including Apache. As a result, the Company relies on cash flows from its subsidiaries, including Apache, to pay dividends with respect to its common stock and to meet its financial obligations, including to service any debt obligations that the Company may incur from time to time in the future. Legal and contractual restrictions in agreements governing future indebtedness of any of the Company’s subsidiaries, as well as the financial condition and future operating requirements of any such subsidiaries, in each case, including Apache, may limit such subsidiaries’ ability to distribute cash to the Company. If Apache or any of the Company’s other subsidiaries is limited in its ability to distribute cash to the Company, or if the earnings or other available assets of the Company’s subsidiaries are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary for the Company to pay dividends with respect to its common stock and/or to meet its financial obligations, then the Company’s business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.
The Company may not obtain the anticipated benefits of the holding company structure.
The anticipated benefits of the holding company structure may not be obtained by the Company if circumstances prevent the Company from taking advantage of the strategic and business opportunities that it expects the structure may afford it. As a result, the Company may incur costs associated with the holding company structure without realizing the anticipated benefits, which could adversely affect the Company’s business, financial condition, cash flows, and results of operations.
Management has dedicated and continues to dedicate significant efforts to implementation of the new holding company structure. These efforts may divert management’s focus and resources from the Company’s strategic initiatives or business opportunities, which could adversely affect the Company’s prospects, business, financial condition, cash flows, and results of operations.2022.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In 2013 and 2014,The following table presents information on shares of common stock repurchased by the Company’sCompany during the quarter ended June 30, 2023:
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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) |
April 1 to April 30, 2023 | | — | | | $ | — | | | — | | | 48,968,089 |
May 1 to May 31, 2023 | | 1,348,347 | | | 33.72 | | | 1,348,347 | | | 47,619,742 |
June 1 to June 30, 2023 | | — | | | — | | | — | | | 47,619,742 |
Total | | 1,348,347 | | $ | 33.72 | | | | | |
(1) During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of up to 40 million shares of the Company’sCompany's common stock, and duringstock. During September of 2022, the fourth quarter of 2018, the Company’sCompany's Board of Directors authorized the purchase of up toan additional 40 million additional shares of the Company’sCompany's common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through March 31, 2021, had repurchased a total of 40 million shares at an average price of $79.18 per share. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the first three months of 2021.shares.
ITEM 5. OTHER INFORMATION
During the three months ended June 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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*101 | – | The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest 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). |
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*101 | – | The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (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
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.
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| | | APA CORPORATION |
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Dated: | May 6, 2021August 3, 2023 | | /s/ STEPHEN J. RINEY |
| | | Stephen J. Riney |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
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Dated: | May 6, 2021August 3, 2023 | | /s/ REBECCA A. HOYT |
| | | Rebecca A. Hoyt |
| | | Senior Vice President, Chief Accounting Officer, and Controller |
| | | (Principal Accounting Officer) |