UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
FORM 10-Q 
(Mark One)  
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2023March 31, 2024
or
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)
Delaware86-1430562
(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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.625 par valueAPANasdaq 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 filerAccelerated 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 October 31, 2023April 30, 2024306,719,421371,192,344 




TABLE OF CONTENTS

ItemItemPageItemPage
PART I - FINANCIAL INFORMATION
PART I - FINANCIAL INFORMATION
PART I - FINANCIAL INFORMATION
PART I - FINANCIAL INFORMATION
1.1.
1.
1.
2.2.2.
3.3.3.
4.4.4.
PART II - OTHER INFORMATION
PART II - OTHER INFORMATION
PART II - OTHER INFORMATION
PART II - OTHER INFORMATION
1.
1.
1.1.
1A.1A.1A.
2.2.2.
5.5.5.
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, the anticipated benefits of the merger (the Callon acquisition) between the Company and Callon Petroleum Company (Callon), the anticipated impact of the Callon acquisition on the combined company’s business and future financial and operating results, and the anticipated financial and operational impact and timing of the expected synergies from the Callon acquisition, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2022,2023, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:
changes in local, regional, national, and international economic conditions, including as a result of any epidemics or pandemics, such as the coronavirus disease (COVID-19) pandemic and any related variants;
the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;
the Company’s commodity hedging arrangements;
the supply and demand for oil, natural gas, NGLs, and other products or services;
production and reserve levels;
drilling risks;
economic and competitive conditions, including market and macro-economic disruptions resulting from the Russian war in Ukraine, the armed conflict in Israel and Gaza, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);
the availability of capital resources;
capital expenditures and other contractual obligations;
currency exchange rates;
weather conditions;
inflation rates;
the impact of changes in tax legislation;
the availability of goods and services;
the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
the Company’s performance on environmental, social, and governance measures;
terrorism or cyberattacks;
the occurrence of property acquisitions or divestitures;
the integration of acquisitions;cyberattacks and terrorism;
the Company’s ability to access the capital markets;
market-related risks, such as general credit, liquidity, and interest-rate risks;
the ability to retain and hire key personnel;
property acquisitions or divestitures;



the integration of acquisitions, including the diversion of management time on integration-related issues for the Callon acquisition and the risk that the Company may not integrate Callon’s operations in a successful manner or in the expected time period;
the risk that the anticipated benefits, derivedcost savings, synergies, and growth from the operating structure implemented pursuantCallon acquisition may not be fully realized or may take longer to realize than expected;
negative effects of the Holding Company Reorganization (as defined in the Notes toCallon acquisition on the Company’s Consolidated Financial Statements contained inbusiness relationships and business generally, the market price of the Company’s Annual Report on Form 10-K forcommon stock, and/or the fiscal year ended December 31, 2022);Company’s operating results;
other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022;2023;
other risks and uncertainties disclosed in the Company’s third-quarter 2023first-quarter 2024 earnings release;
other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q; and
other factors disclosed in the other filings that the Company makes with the Securities and Exchange Commission.
Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.



DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:
“3-D” means three-dimensional.
“4-D” means four-dimensional.
“b/d” means barrels of oil or NGLs per day.
“bbl” or “bbls” means barrel or barrels of oil or NGLs.
“bcf” means billion cubic feet of natural gas.
“bcf/d” means one bcf per day.
“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.
“boe/d” means boe per day.
“Btu” means a British thermal unit, a measure of heating value.
“Liquids” means oil and NGLs.
“LNG” means liquefied natural gas.
“Mb/d” means Mbbls per day.
“Mbbls” means thousand barrels of oil or NGLs.
“Mboe” means thousand boe.
“Mboe/d” means Mboe per day.
“Mcf” means thousand cubic feet of natural gas.
“Mcf/d” means Mcf per day.
“MMbbls” means million barrels of oil or NGLs.
“MMboe” means million boe.
“MMBtu” means million Btu.
“MMBtu/d” means MMBtu per day.
“MMcf” means million cubic feet of natural gas.
“MMcf/d” means MMcf per day.
“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.
“NYMEX” means New York Mercantile Exchange.
“oil” includes crude oil and condensate.
“PUD” means proved undeveloped.
“SEC” means the United States Securities and Exchange Commission.
“Tcf” means trillion cubic feet of natural gas.
“U.K.” means United Kingdom.
“U.S.” means United States.
With respect to information relating to the Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.
References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.



PART I – FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
For the Quarter Ended
March 31,
For the Quarter Ended
March 31,
For the Quarter Ended
March 31,
2024
2024
2024
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions, except share data)(In millions, except share data)
REVENUES AND OTHER:REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)
Oil, natural gas, and natural gas liquids production revenues(1)
$2,079 $2,302 $5,500 $7,147 
Oil, natural gas, and natural gas liquids production revenues(1)
Oil, natural gas, and natural gas liquids production revenues(1)
Purchased oil and gas sales(1)
Purchased oil and gas sales(1)
Purchased oil and gas sales(1)
Purchased oil and gas sales(1)
229 585 612 1,456 
Total revenuesTotal revenues2,308 2,887 6,112 8,603 
Total revenues
Total revenues
Derivative instrument gains (losses), net
Derivative instrument gains (losses), net
Derivative instrument gains (losses), netDerivative instrument gains (losses), net— (44)104 (138)
Gain on divestitures, netGain on divestitures, net31 1,180 
Gain on divestitures, net
Gain on divestitures, net
Loss on previously sold Gulf of Mexico properties
Loss on previously sold Gulf of Mexico properties
Loss on previously sold Gulf of Mexico properties
Other, netOther, net— (2)77 107 
2,309 2,872 6,300 9,752 
Other, net
Other, net
1,903
1,903
1,903
OPERATING EXPENSES:OPERATING EXPENSES:
Lease operating expenses394 364 1,076 1,067 
OPERATING EXPENSES:
OPERATING EXPENSES:
Lease operating expenses(1)
Lease operating expenses(1)
Lease operating expenses(1)
Gathering, processing, and transmission(1)
Gathering, processing, and transmission(1)
Gathering, processing, and transmission(1)
Gathering, processing, and transmission(1)
89 99 245 274 
Purchased oil and gas costs(1)
Purchased oil and gas costs(1)
211 573 558 1,452 
Purchased oil and gas costs(1)
Purchased oil and gas costs(1)
Taxes other than income
Taxes other than income
Taxes other than incomeTaxes other than income61 82 163 230 
ExplorationExploration49 95 144 193 
Exploration
Exploration
General and administrative
General and administrative
General and administrativeGeneral and administrative139 69 276 314 
Transaction, reorganization, and separationTransaction, reorganization, and separation11 21 
Transaction, reorganization, and separation
Transaction, reorganization, and separation
Depreciation, depletion, and amortization
Depreciation, depletion, and amortization
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization418 310 1,117 879 
Asset retirement obligation accretionAsset retirement obligation accretion29 29 86 87 
Impairments— — 46 — 
Asset retirement obligation accretion
Asset retirement obligation accretion
Financing costs, netFinancing costs, net81 75 235 303 
1,476 1,700 3,957 4,820 
Financing costs, net
Financing costs, net
1,456
1,456
1,456
NET INCOME BEFORE INCOME TAXES
NET INCOME BEFORE INCOME TAXES
NET INCOME BEFORE INCOME TAXESNET INCOME BEFORE INCOME TAXES833 1,172 2,343 4,932 
Current income tax provisionCurrent income tax provision422 357 1,022 1,164 
Current income tax provision
Current income tax provision
Deferred income tax provision (benefit)
Deferred income tax provision (benefit)
Deferred income tax provision (benefit)Deferred income tax provision (benefit)(144)285 (22)225 
NET INCOME INCLUDING NONCONTROLLING INTERESTSNET INCOME INCLUDING NONCONTROLLING INTERESTS555 530 1,343 3,543 
Net income attributable to noncontrolling interest – Egypt96 108 261 368 
Net income attributable to noncontrolling interest – Altus— — — 14 
Net loss attributable to Altus Preferred Unit limited partners— — — (70)
NET INCOME INCLUDING NONCONTROLLING INTERESTS
NET INCOME INCLUDING NONCONTROLLING INTERESTS
Net income attributable to noncontrolling interest
Net income attributable to noncontrolling interest
Net income attributable to noncontrolling interest
NET INCOME ATTRIBUTABLE TO COMMON STOCK
NET INCOME ATTRIBUTABLE TO COMMON STOCK
NET INCOME ATTRIBUTABLE TO COMMON STOCKNET INCOME ATTRIBUTABLE TO COMMON STOCK$459 $422 $1,082 $3,231 
NET INCOME PER COMMON SHARE:NET INCOME PER COMMON SHARE:
NET INCOME PER COMMON SHARE:
NET INCOME PER COMMON SHARE:
Basic
Basic
BasicBasic$1.49 $1.28 $3.50 $9.54 
DilutedDiluted$1.49 $1.28 $3.50 $9.51 
Diluted
Diluted
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BasicBasic308 329 309 339 
Basic
Basic
DilutedDiluted308 330 309 340 
Diluted
Diluted
(1)    For transactions associated with Kinetik prior to the Company’s sale of its remaining shares of Kinetik Class A Common Stock and the resignation of the Company’s designated director from the Kinetik board of directors, refer to Note 6—Equity Method Interests for further detail..
The accompanying notes to consolidated financial statements are an integral part of this statement.
1


APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTSNET INCOME INCLUDING NONCONTROLLING INTERESTS$555 $530 $1,343 $3,543 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OTHER COMPREHENSIVE INCOME, NET OF TAX:
OTHER COMPREHENSIVE INCOME, NET OF TAX:
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Pension and postretirement benefit plan
Pension and postretirement benefit plan
Pension and postretirement benefit planPension and postretirement benefit plan— — (1)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTSCOMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS555 530 1,346 3,542 
Comprehensive income attributable to noncontrolling interest – Egypt96 108 261 368 
Comprehensive income attributable to noncontrolling interest – Altus— — — 14 
Comprehensive loss attributable to Altus Preferred Unit limited partners— — — (70)
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS
Comprehensive income attributable to noncontrolling interest
Comprehensive income attributable to noncontrolling interest
Comprehensive income attributable to noncontrolling interest
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCKCOMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK$459 $422 $1,085 $3,230 
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

The accompanying notes to consolidated financial statements are an integral part of this statement.
2


APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
For the Three Months Ended
March 31,
For the Three Months Ended
March 31,
20242023
For the Nine Months Ended
September 30,
20232022
(In millions)(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interestsNet income including noncontrolling interests$1,343 $3,543 
Net income including noncontrolling interests
Net income including noncontrolling interests
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
Unrealized derivative instrument (gains) losses, netUnrealized derivative instrument (gains) losses, net(61)119 
Gain on divestitures, netGain on divestitures, net(7)(1,180)
Exploratory dry hole expense and unproved leasehold impairmentsExploratory dry hole expense and unproved leasehold impairments91 129 
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization1,117 879 
Asset retirement obligation accretionAsset retirement obligation accretion86 87 
Impairments46 — 
Provision for (benefit from) deferred income taxesProvision for (benefit from) deferred income taxes(22)225 
(Gain) loss on extinguishment of debt(9)67 
Provision for (benefit from) deferred income taxes
Provision for (benefit from) deferred income taxes
Gain on extinguishment of debt
Loss on previously sold Gulf of Mexico properties
Other, netOther, net(45)(91)
Changes in operating assets and liabilities:Changes in operating assets and liabilities:
Receivables
Receivables
ReceivablesReceivables(289)(554)
InventoriesInventories19 (81)
Drilling advances and other current assetsDrilling advances and other current assets40 
Deferred charges and other long-term assetsDeferred charges and other long-term assets227 (3)
Accounts payableAccounts payable(2)175 
Accrued expensesAccrued expenses249 
Deferred credits and noncurrent liabilitiesDeferred credits and noncurrent liabilities(436)(41)
NET CASH PROVIDED BY OPERATING ACTIVITIESNET CASH PROVIDED BY OPERATING ACTIVITIES2,099 3,530 
CASH FLOWS FROM INVESTING ACTIVITIES:CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas propertyAdditions to upstream oil and gas property(1,747)(1,168)
Acquisition of Delaware Basin properties(24)(563)
Additions to upstream oil and gas property
Additions to upstream oil and gas property
Leasehold and property acquisitionsLeasehold and property acquisitions(11)(30)
Proceeds from sale of oil and gas properties29 778 
Proceeds from sale of Kinetik shares— 224 
Deconsolidation of Altus cash and cash equivalents— (143)
Leasehold and property acquisitions
Leasehold and property acquisitions
Proceeds from asset divestitures
Proceeds from sale of Kinetik Shares
Other, netOther, net(29)
NET CASH USED IN INVESTING ACTIVITIESNET CASH USED IN INVESTING ACTIVITIES(1,782)(894)
CASH FLOWS FROM FINANCING ACTIVITIES:CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) revolving credit facilities, net202 (22)
Proceeds from (payments on) commercial paper and revolving credit facilities, net
Proceeds from (payments on) commercial paper and revolving credit facilities, net
Proceeds from (payments on) commercial paper and revolving credit facilities, net
Payments on Apache fixed-rate debtPayments on Apache fixed-rate debt(65)(1,370)
Distributions to noncontrolling interest – Egypt(154)(237)
Payments on Apache fixed-rate debt
Payments on Apache fixed-rate debt
Distributions to noncontrolling interest
Treasury stock activity, netTreasury stock activity, net(208)(884)
Dividends paid to APA common stockholdersDividends paid to APA common stockholders(232)(127)
Other, netOther, net(10)(30)
NET CASH USED IN FINANCING ACTIVITIES(467)(2,670)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
NET DECREASE IN CASH AND CASH EQUIVALENTS(150)(34)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEARCASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR245 302 
CASH AND CASH EQUIVALENTS AT END OF PERIODCASH AND CASH EQUIVALENTS AT END OF PERIOD$95 $268 
SUPPLEMENTARY CASH FLOW DATA:SUPPLEMENTARY CASH FLOW DATA:
SUPPLEMENTARY CASH FLOW DATA:
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest
Interest paid, net of capitalized interest
Interest paid, net of capitalized interestInterest paid, net of capitalized interest$278 $274 
Income taxes paid, net of refundsIncome taxes paid, net of refunds867 1,029 
The accompanying notes to consolidated financial statements are an integral part of this statement.
3


APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
March 31,
2024
March 31,
2024
December 31,
2023
September 30,
2023
December 31,
2022
(In millions, except share data)
(In millions, except share data)
(In millions, except share data)
(In millions, except share data)
ASSETSASSETS
CURRENT ASSETS:CURRENT ASSETS:
CURRENT ASSETS:
CURRENT ASSETS:
Cash and cash equivalentsCash and cash equivalents$95 $245 
Receivables, net of allowance of $103 and $1171,753 1,466 
Cash and cash equivalents
Cash and cash equivalents
Receivables, net of allowance of $110 and $114
Other current assets (Note 5)
Other current assets (Note 5)
952 997 
2,800 2,708 
2,506
PROPERTY AND EQUIPMENT:PROPERTY AND EQUIPMENT:
Oil and gas properties
Oil and gas properties
Oil and gas propertiesOil and gas properties43,908 42,356 
Gathering, processing, and transmission facilitiesGathering, processing, and transmission facilities447 449 
OtherOther613 613 
Less: Accumulated depreciation, depletion, and amortizationLess: Accumulated depreciation, depletion, and amortization(35,468)(34,406)
9,500 9,012 
10,143
OTHER ASSETS:OTHER ASSETS:
Equity method interests (Note 6)
Equity method interests (Note 6)
681 624 
Equity method interests (Note 6)
Equity method interests (Note 6)
Decommissioning security for sold Gulf of Mexico properties (Note 11)
Decommissioning security for sold Gulf of Mexico properties (Note 11)
38 217 
Deferred tax asset (Note 10)
Deferred charges and otherDeferred charges and other526 586 
$13,545 $13,147 
$
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITYLIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY
CURRENT LIABILITIES:CURRENT LIABILITIES:
CURRENT LIABILITIES:
CURRENT LIABILITIES:
Accounts payable
Accounts payable
Accounts payableAccounts payable$741 $771 
Current debtCurrent debt
Other current liabilities (Note 7)
Other current liabilities (Note 7)
1,892 2,143 
2,635 2,916 
2,152
LONG-TERM DEBT (Note 9)
LONG-TERM DEBT (Note 9)
5,582 5,451 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes305 314 
Deferred tax liability (Note 10)
Deferred tax liability (Note 10)
Deferred tax liability (Note 10)
Asset retirement obligation (Note 8)
Asset retirement obligation (Note 8)
2,006 1,940 
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)
470 738 
OtherOther440 443 
3,221 3,435 
3,969
EQUITY:EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 420,593,611 and 419,869,987 shares issued, respectively263 262 
Common stock, $0.625 par, 860,000,000 shares authorized, 421,137,927 and 420,595,901 shares issued, respectively
Common stock, $0.625 par, 860,000,000 shares authorized, 421,137,927 and 420,595,901 shares issued, respectively
Common stock, $0.625 par, 860,000,000 shares authorized, 421,137,927 and 420,595,901 shares issued, respectively
Paid-in capitalPaid-in capital11,197 11,420 
Accumulated deficitAccumulated deficit(4,732)(5,814)
Treasury stock, at cost, 113,797,342 and 108,310,838 shares, respectively(5,667)(5,459)
Treasury stock, at cost, 120,031,117 and 117,020,000 shares, respectively
Accumulated other comprehensive incomeAccumulated other comprehensive income17 14 
APA SHAREHOLDERS’ EQUITYAPA SHAREHOLDERS’ EQUITY1,078 423 
Noncontrolling interest – Egypt1,029 922 
Noncontrolling interest
TOTAL EQUITYTOTAL EQUITY2,107 1,345 
$13,545 $13,147 
$


The accompanying notes to consolidated financial statements are an integral part of this statement.
4


APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS
(Unaudited)
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)
Common
Stock
Paid-In
Capital
Accumulated DeficitTreasury
Stock
Accumulated
Other
Comprehensive
Income
APA SHAREHOLDERS’
EQUITY
Noncontrolling
Interests(1)
TOTAL
EQUITY
(In millions)
For the Quarter Ended September 30, 2022
Balance at June 30, 2022$— $262 $11,567 $(6,679)$(4,587)$21 $584 $921 $1,505 
Net income attributable to common stock— — — 422 — — 422 — 422 
Net income attributable to noncontrolling interest – Egypt— — — — — — — 108 108 
Distributions to noncontrolling interest – Egypt— — — — — — — (78)(78)
Common dividends declared ($0.25 per share)— — (80)— — — (80)— (80)
Treasury stock activity, net— — — — (333)— (333)— (333)
Other— — — — — — 
Balance at September 30, 2022$— $262 $11,494 $(6,257)$(4,920)$21 $600 $951 $1,551 
For the Quarter Ended September 30, 2023
Balance at June 30, 2023$— $263 $11,267 $(5,191)$(5,647)$17 $709 $987 $1,696 
Net income attributable to common stock— — — 459 — — 459 — 459 
Net income attributable to noncontrolling interest – Egypt— — — — — — — 96 96 
Distributions to noncontrolling interest – Egypt— — — — — — — (54)(54)
Common dividends declared ($0.25 per share)— — (77)— — — (77)— (77)
Treasury stock activity, net— — — — (20)— (20)— (20)
Other— — — — — — 
Balance at September 30, 2023$— $263 $11,197 $(4,732)$(5,667)$17 $1,078 $1,029 $2,107 
Common
Stock
Paid-In
Capital
Accumulated DeficitTreasury
Stock
Accumulated
Other
Comprehensive
Income
APA SHAREHOLDERS’
EQUITY
Noncontrolling
Interest
TOTAL
EQUITY
(In millions)
For the Quarter Ended March 31, 2023
Balance at December 31, 2022$262 $11,420 $(5,814)$(5,459)$14 $423 $922 $1,345 
Net income attributable to common stock— — 242 — — 242 — 242 
Net income attributable to noncontrolling interest— — — — — — 84 84 
Distributions to noncontrolling interest— — — — — — (17)(17)
Common dividends declared ($0.25 per share)— (78)— — — (78)— (78)
Treasury stock activity, net— — — (142)— (142)— (142)
Other(5)— — (1)— (1)
Balance at March 31, 2023$263 $11,337 $(5,572)$(5,601)$17 $444 $989 $1,433 
For the Quarter Ended March 31, 2024
Balance at December 31, 2023$263 $11,126 $(2,959)$(5,790)$15 $2,655 $1,036 $3,691 
Net income attributable to common stock— — 132 — — 132 — 132 
Net income attributable to noncontrolling interest— — — — — — 80 80 
Distributions to noncontrolling interest— — — — — — (70)(70)
Common dividends declared ($0.25 per share)— (75)— — — (75)— (75)
Treasury stock activity, net— — — (101)— (101)— (101)
Other— (4)— — — (4)— (4)
Balance at March 31, 2024$263 $11,047 $(2,827)$(5,891)$15 $2,607 $1,046 $3,653 
(1)    As a result of the BCP Business Combination (as defined herein), the Company deconsolidated Altus (as defined herein) on February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail.

The accompanying notes to consolidated financial statements are an integral part of this statement.
5


APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS - Continued
(Unaudited)
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)
Common
Stock
Paid-In
Capital
Accumulated DeficitTreasury
Stock
Accumulated
Other
Comprehensive
Income
APA
SHAREHOLDERS’
EQUITY (DEFICIT)
Noncontrolling
Interests(1)
TOTAL EQUITY
(DEFICIT)
(In millions)
For the Nine Months Ended September 30, 2022
Balance at December 31, 2021$712 $262 $11,645 $(9,488)$(4,036)$22 $(1,595)$878 $(717)
Net income attributable to common stock— 3,231 — — 3,231 — 3,231 
Net income attributable to noncontrolling interest – Egypt— — — — — — — 368 368 
Net income attributable to noncontrolling interest – Altus— — — — — — — 14 14 
Net loss attributable to Altus Preferred Unit limited partners(70)— — — — — — — — 
Distributions to noncontrolling interest – Egypt— — — — — — — (237)(237)
Common dividends declared ($0.50 per share)— — (165)— — — (165)— (165)
Deconsolidation of Altus(642)— — — — — — (72)(72)
Treasury stock activity, net— — — — (884)— (884)— (884)
Other— — 14 — — (1)13 — 13 
Balance at September 30, 2022$— $262 $11,494 $(6,257)$(4,920)$21 $600 $951 $1,551 
For the Nine Months Ended September 30, 2023
Balance at December 31, 2022$— $262 $11,420 $(5,814)$(5,459)$14 $423 $922 $1,345 
Net income attributable to common stock— — — 1,082 — — 1,082 — 1,082 
Net income attributable to noncontrolling interest – Egypt— — — — — — — 261 261 
Distributions to noncontrolling interest – Egypt— — — — — — — (154)(154)
Common dividends declared ($0.75 per share)— — (232)— — — (232)— (232)
Treasury stock activity, net— — — — (208)— (208)— (208)
Other— — — 13 — 13 
Balance at September 30, 2023$— $263 $11,197 $(4,732)$(5,667)$17 $1,078 $1,029 $2,107 
(1)    As a result of the BCP Business Combination (as defined herein), the Company deconsolidated Altus (as defined herein) on February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail.

The accompanying notes to consolidated financial statements are an integral part of this statement.
6


APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022,2023, which contains a summary of the Company’s significant accounting policies and other disclosures.
1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2023,March 31, 2024, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023. The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.
The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.
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. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.
Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors owned a minority interest of approximately 21 percent of Altus Midstream Company (ALTM or Altus), which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which APA consolidated because a wholly owned subsidiary of APA had a controlling financial interest and was determined to be the primary beneficiary.
On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP.As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.
7


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 areDuring each of the periods ended March 31, 2024 and 2023, the Company had a designated director on the Kinetik Holdings Inc. (Kinetik) board of directors. As a result, the Company is considered to have had significant influence over Kinetik for all periods presented. The Company’s designated director resigned from the Kinetik board of directors on April 3, 2024.
As of December 31, 2023, the Company held shares of Kinetik Class A Common Stock (Kinetik Shares), which were recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. TheOn March 18, 2024, the Company elected the fair value option to account forsold its equity method interest in Kinetik.remaining Kinetik Shares. Refer to Note 6—Equity Method Interests for further detail.

6


Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Refer to Note 4—Derivative Instruments and Hedging Activities, Note 6—Equity Method Interests, and Note 9—Debt and Financing Costs for further detail regarding the Company’s fair value measurements recorded on a recurring basis.
During the three and nine months ended September 30,March 31, 2024 and 2023, and 2022, the Company recorded no asset impairments in connection with fair value assessments.
Revenue Recognition
There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2023 and 2022.
8


Receivables from contracts with customers, including receivables for purchased oil and gas sales in each case,and net of allowance for credit losses, were $1.6$1.4 billion and $1.3$1.5 billion as of September 30, 2023March 31, 2024 and December 31, 2022,2023, respectively. Payments under all contracts with customers are typically due and received within a short-term period of 60 daysone year or less, after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a longer-than-usual delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC.
Oil and gas production revenues include income taxes that will be paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.
Refer to Note 13—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.
7


In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysicalproduction 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 explorationactivities, and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. Ifif management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
9


Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.
Gathering, Processing, and Transmission (GPT) Facilities
GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
New Pronouncements Issued But Not Yet Adopted
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, 2023.
8


2.    ACQUISITIONS AND DIVESTITURES
20232024 Activity
Callon Petroleum Company Acquisition
On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024.
Subject to the terms of the merger agreement, each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.
Upon completing the acquisition, APA refinanced substantially all of Callon’s debt by borrowing under APA’s US dollar denominated syndicated credit facilities. Refer to Note 9—Debt and Financing Costs for further detail.
Sale of Kinetik Shares
On March 18, 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. Refer to Note 6—Equity Method Interests for further detail.
Leasehold and Property Acquisitions
During the thirdfirst quarter of 2024, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $63 million.
U.S. Divestitures
During the first nine monthsquarter of 2024, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $27 million, recognizing a gain of approximately $7 million upon closing of these transactions.
2023 Activity
Leasehold and Property Acquisitions
During the first quarter of 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $1 million and $11 million, respectively.$6 million.
U.S. Divestitures
During the thirdfirst quarter and first nine months of 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $1$21 million, and $29 million, respectively, recognizing a gain of approximately $1 million and $7 million, respectively, upon closing of these transactions.
10


2022 Activity
During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. The Company recorded $581 million for proved properties, $38 million for unproved leasehold, and $4 million for abandonment obligations.
During the third quarter and first nine months of 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $3 million and $30 million, respectively.
During the third quarter and first nine months of 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $37 million and $52 million, respectively, recognizing a gain of approximately $34 million and $36 million, respectively, upon closing of these transactions.
During the first nine months of 2022, the Company completed a transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million.
The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed.
As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s share of ALTM’s deconsolidated balance sheet of $193 million and the fair value of $802 million of its approximate 20 percent retained ownership in the combined entity.
During the first quarter of 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and recognized a loss of $25 million, including transaction fees. Refer to Note 6—Equity Method Interests for further detail.
3.    CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $541$587 million and $474$586 million as of September 30, 2023March 31, 2024 and December 31, 2022,2023, respectively. The increase is attributable to additional drilling activity offshore Suriname and in Egypt. Approximately $5$51 million of suspended well costs previously capitalized for greater than one year at December 31, 20222023 were charged to dry hole expense during the thirdfirst quarter of 2023.2024. This was offset by increased capital exploratory well costs attributable to additional drilling activity in Egypt and in the U.S. in the first quarter of 2024.
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.
9


4.    DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.
11


Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2023,March 31, 2024, the Company had derivative positions with sevenfour counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.
Derivative Instruments
Commodity Derivative Instruments
As of September 30, 2023,March 31, 2024, the Company had the following open natural gas financial basis swap contracts:
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)
Weighted Average Price DifferentialMMBtu
(in 000’s)
Weighted Average Price Differential
October—December 2023NYMEX Henry Hub/IF Waha18,400 $(1.15)— 
October—December 2023NYMEX Henry Hub/IF HSC— 18,400 $(0.08)
January—June 2024NYMEX Henry Hub/IF Waha16,380 $(1.15)— 
January—June 2024NYMEX Henry Hub/IF HSC— 16,380 $(0.10)
Basis Swap PurchasedBasis Swap Sold
Production PeriodSettlement IndexMMBtu
(in 000’s)
Weighted Average Price DifferentialMMBtu
(in 000’s)
Weighted Average Price Differential
April—June 2024NYMEX Henry Hub/IF Waha8,190 $(1.15)— 
April—June 2024NYMEX Henry Hub/IF HSC— 8,190 $(0.10)
Fair Value Measurements
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)
Quoted Price in Active Markets
(Level 1)
Quoted Price in Active Markets
(Level 1)
Significant Other Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Total
Fair Value
Netting(1)
Carrying Amount
(In millions)
(In millions)
(In millions)
March 31, 2024
Liabilities:
Liabilities:
Liabilities:
Commodity derivative instruments
Commodity derivative instruments
Commodity derivative instruments
Fair Value Measurements Using
Quoted Price in Active Markets
(Level 1)
Significant Other Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Total
Fair Value
Netting(1)
Carrying Amount
December 31, 2023
(In millions)
September 30, 2023
December 31, 2023
December 31, 2023
Assets:Assets:
Assets:
Assets:
Commodity derivative instruments
Commodity derivative instruments
Commodity derivative instrumentsCommodity derivative instruments$— $16 $— $16 $— $16 
December 31, 2022
Assets:
Commodity derivative instruments$— $$— $$— $
Liabilities:
Commodity derivative instruments— 50 — 50 — 50 
(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.
1210


The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.
Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
September 30,
2023
December 31,
2022
(In millions)
Current Assets: Other current assets$16 $— 
Other Assets: Deferred charges and other— 
Total derivative assets$16 $
Current Liabilities: Other current liabilities$— $50 
Total derivative liabilities$— $50 
March 31,
2024
December 31,
2023
(In millions)
Current Assets: Other current assets$— $
Total derivative assets$— $
Current Liabilities: Other current liabilities$$— 
Total derivative liabilities$$— 
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:
2024
2024
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)(In millions)
Realized:Realized:
Commodity derivative instrumentsCommodity derivative instruments$19 $(2)$43 $(11)
Foreign currency derivative instruments— (6)— (8)
Realized gains (losses), net19 (8)43 (19)
Commodity derivative instruments
Commodity derivative instruments
Realized gains, net
Realized gains, net
Realized gains, net
Unrealized:
Unrealized:
Unrealized:Unrealized:
Commodity derivative instrumentsCommodity derivative instruments(19)(35)61 (79)
Commodity derivative instruments
Commodity derivative instruments
Foreign currency derivative instruments— (1)— (9)
Preferred Units embedded derivative— — — (31)
Unrealized gains (losses), net
Unrealized gains (losses), net
Unrealized gains (losses), netUnrealized gains (losses), net(19)(36)61 (119)
Derivative instrument gains (losses), netDerivative instrument gains (losses), net$— $(44)$104 $(138)
Derivative instrument gains (losses), net
Derivative instrument gains (losses), net
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
5.    OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets:
March 31,
2024
March 31,
2024
December 31,
2023
September 30,
2023
December 31,
2022
(In millions)(In millions)
InventoriesInventories$443 $427 
Drilling advancesDrilling advances87 89 
Prepaid assets and otherPrepaid assets and other49 31 
Prepaid assets and other
Prepaid assets and other
Current decommissioning security for sold Gulf of Mexico assetsCurrent decommissioning security for sold Gulf of Mexico assets373 450 
Total Other current assetsTotal Other current assets$952 $997 
1311


6.    EQUITY METHOD INTERESTS
The Kinetik Class A Common Stock held byAs of December 31, 2023, the Company is treated as an interest in equity securities measuredheld 13.1 million Kinetik Shares, which were recorded at fair value.value of $437 million and reflected separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik iswas determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.
The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. InOn March 2022,18, 2024, the Company sold four millionits remaining Kinetik Shares for cash proceeds of $428 million.
Prior to the Company’s sale of its sharesremaining Kinetik Shares and the resignation of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statementdesignated director from the Kinetik board of consolidated operations. Refer to Note 2—Acquisitions and Divestitures for further detail. Duringdirectors, the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million shares.
The Company has received approximately 2.5 million shares of Kinetik’s Class A Common Stock as paid-in-kind dividends through September 30, 2023. As of September 30, 2023, the Company’s ownership of 20.2 million shares represented approximately 14 percent of Kinetik’s outstanding Class A Common Stock.
The Company recorded changes in the fair value of its equity method interest in Kinetik totaling losses of $14$9 million and $17 million in the third quarters of 2023 and 2022, respectively, and gains of $57 million and $49$19 million in the first nine monthsquarters of 20232024 and 2022,2023, respectively. These gains and losses were recorded as a component of “Revenues and other”Other” in the Company’s statement of consolidated operations.
The following table represents related party sales and costs associated with Kinetik:Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)
Natural gas and NGLs sales$35 $— $78 $— 
Purchased oil and gas sales11 — 18 — 
$46 $— $96 $— 
Gathering, processing, and transmission costs$26 $28 $81 $64 
Purchased oil and gas costs37 — 65 — 
$63 $28 $146 $64 
As of September 30, 2023, the Company has recorded accrued costs payable to Kinetik of approximately $43 million and receivables from Kinetik of approximately $29 million.
For the Quarter Ended
March 31,
20242023
(In millions)
Natural gas and NGLs sales$13 $14 
Purchased oil and gas sales22 — 
$35 $14 
Gathering, processing, and transmission costs$23 $26 
Purchased oil and gas costs23 — 
Lease operating expenses— 
$48 $26 
7.    OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities:
March 31,
2024
March 31,
2024
December 31,
2023
September 30,
2023
December 31,
2022
(In millions)(In millions)
Accrued operating expensesAccrued operating expenses$161 $145 
Accrued exploration and developmentAccrued exploration and development328 333 
Accrued compensation and benefitsAccrued compensation and benefits379 514 
Accrued interestAccrued interest66 97 
Accrued income taxesAccrued income taxes228 90 
Current asset retirement obligationCurrent asset retirement obligation55 55 
Current operating lease liabilityCurrent operating lease liability108 167 
Current decommissioning contingency for sold Gulf of Mexico propertiesCurrent decommissioning contingency for sold Gulf of Mexico properties225 450 
Current decommissioning contingency for sold Gulf of Mexico properties
Current decommissioning contingency for sold Gulf of Mexico properties
OtherOther342 292 
Total Other current liabilitiesTotal Other current liabilities$1,892 $2,143 
1412


8.    ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
September 30,March 31,
20232024
 (In millions)
Asset retirement obligation, December 31, 20222023$1,9952,438 
Liabilities incurred141 
Liabilities acquired
Liabilities settled(34)(9)
Accretion expense8640 
Revisions in estimated liabilities
Asset retirement obligation, September 30, 2023March 31, 20242,0612,475 
Less current portion(55)(75)
Asset retirement obligation, long-term$2,0062,400 
9.    DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
March 31,
2024
March 31,
2024
December 31,
2023
September 30,
2023
December 31,
2022
(In millions)
(In millions)
(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)
Commercial paper and syndicated credit facilities(2)
(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)
$4,835 $4,908 
Syndicated credit facilities(2)
768 566 
Apache finance lease obligations
Apache finance lease obligations
Apache finance lease obligationsApache finance lease obligations33 34 
Unamortized discountUnamortized discount(26)(27)
Debt issuance costsDebt issuance costs(26)(28)
Total debtTotal debt5,584 5,453 
Current maturitiesCurrent maturities(2)(2)
Long-term debtLong-term debt$5,582 $5,451 
(1)    The fair values of the Apache notes and debentures were $4.1$4.3 billion and $4.2 billion asat each of September 30, 2023March 31, 2024 and December 31, 2022, respectively.2023.
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 commercial paper and credit facilities approximates fair value because interest rates are variable and reflective of market rates.
At each of September 30, 2023March 31, 2024 and December 31, 2022,2023, current debt included $2 million of finance lease obligations.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
 
For the Quarter Ended
March 31,
 20242023
 (In millions)
Interest expense$85 $88 
Amortization of debt issuance costs
Capitalized interest(7)(6)
Gain on extinguishment of debt— (9)
Interest income(3)(2)
Financing costs, net$76 $72 
During the nine monthsquarter ended September 30,March 31, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million.cash. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
1513


Unsecured 2022 Committed Bank Credit Facilities
On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).purposes.
One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each Newof the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.
As of September 30, 2023,March 31, 2024, there were $768$30 million of borrowings under the USD Agreement and an aggregate £572£348 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023,March 31, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022,2023, there were $566$372 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement and an aggregate £652£348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which requiredrequire such support afterwhile Apache’s credit rating by Standard & Poor’s remains below BBB; on March 26, 2020, Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020., which was affirmed in 2023.
Uncommitted Lines of Credit
Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023March 31, 2024 and December 31, 2022,2023, there were no outstanding borrowings under these facilities. AsAt each of September 30,March 31, 2024 and December 31, 2023, there were £185£416 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17$2 million in letters of credit outstanding under these facilities.
Financing Costs, NetCommercial Paper Program
In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.
Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of March 31, 2024, there was $340 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
14


Unsecured Committed Term Loan Facility
On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only on the date of closing of transactions under the Merger Agreement. Refer to “Subsequent Events” for further detail. Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.
Subsequent Events
On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement.APA borrowed an aggregate $1.5 billion in senior unsecured term loans that mature April 1, 2027. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement.
The following table presentslenders under the componentsTerm Loan Credit Agreement committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA available for borrowing only once upon the date of the Company’s financing costs, net:closings under the Merger Agreement and Term Loan Credit Agreement, of which $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). APA elected to borrow only under the 3-Year Tranche Loans and to allow the lender commitments for the 364-Day Tranche Loans to expire.
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
 2023202220232022
 (In millions)
Interest expense$89 $80 $266 $249 
Amortization of debt issuance costs
Capitalized interest(7)(5)(18)(13)
(Gain) loss on extinguishment of debt— — (9)67 
Interest income(2)(1)(7)(8)
Financing costs, net$81 $75 $235 $303 
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes). On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. Given the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and USD Agreement:
Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
On April 26, 2024, Callon notified holders of its election to fully redeem on May 6, 2024 the outstanding $8.3 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $15.6 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date.
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.
1615


During the third quarter of 2023, theThe Company’s effective income tax rate was primarily impacted by a decrease infor the amountthree months ended March 31, 2024 differed from the U.S. federal statutory income tax rate of valuation allowance against its U.S. deferred tax assets.21 percent due to taxes on foreign operations. The Company’s 2023 year-to-date effective income tax rate was primarily impacted byfor the three months ended March 31, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent,In December 2021, the Organisation for Economic Co-operation and included amendments to the Energy (Oil and Gas) Profits Levy ActDevelopment issued Pillar Two Model Rules introducing a new global minimum tax of 2022, increasing the levy from15 percent on a 25 percent rate to a 35 percent rate,country-by-country basis, with certain aspects effective for the period ofin certain jurisdictions on 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 2023,2024. Although the Company recorded a deferred tax expense of $174 million relatedcontinues to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S.monitor 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 continuinglegislation to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact ofimplement these provisions on the Company. Under the existing guidance,rules in countries where the Company could be impacted, APA does not believeexpect that the IRAPillar Two framework will have a material impact for 2023.
The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.consolidated financial statements.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
11.    COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2023,March 31, 2024, the Company has an accrued liability of approximately $49$84 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
17


2023.
Argentine Environmental Claims
On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration 
As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022,2023, 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.
16


Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgmentsWithout acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The settlement is subject to court approval, which the parties hope to receive at some point in the first half of 2024. The consideration to be provided by the Company in the settlement will not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only two remaining coastal zone lawsuits, one filed by the City of New Orleans against the Company might be possible,and a number of oil and gas operators and the other filed against Callon Offshore Production, Inc., among many other oil and gas operators, and pending in St. Bernard Parish, Louisiana. The Company intends to vigorously oppose these claims.will now oversee the latter lawsuit as a result of the merger with Callon Petroleum Company.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.
18


Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et.al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized by the end of 2023.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit.
17


Kulp Minerals Lawsuit
On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges, among other things, that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. With no admission, concession, or finding of any fault, liability, or wrongdoing, but only to avoid the expense and uncertainty of litigation, the parties have agreed to a settlement resolving all claims made against the defendants by the class. The Company intendssettlement agreement will be subject to vigorously defend this lawsuit.court approval, and a hearing is expected to be held in the coming months. The settlement will not have a material effect on the Company’s financial position, results of operations, or liquidity and is subject to insurance coverage that companies have for these types of claims.
On January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, on February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases have now been consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intendfiled a motion to vigorously defend these lawsuits.dismiss the consolidated lawsuits, which is fully briefed and will remain pending following settlement of the
19


Plymouth County Retirement System
case noted above.
Environmental Matters
As of September 30, 2023,March 31, 2024, the Company had an undiscounted reserve for environmental remediation of approximately $5 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings.
OnThen 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 noticenotices and information request involverequests involved alleged emissions control and reporting violations. The Company is cooperatingcooperated with the EPA, and has responded to the information request.requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which has been approved and entered by the Court. The EPA has referredconsideration provided by the notice for civil enforcement proceedings.Company in connection with the consent decree, which includes a $4 million payment, will not have a material impact on the Company’s financial position.
The Company is not aware of any environmental claims existing as of September 30, 2023,March 31, 2024, 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.
18


Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under(and subsequently emerged from) Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
protection. On August 3, 2020, Fieldwood again filed for protection under(and subsequently emerged from) Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Courtbankruptcy protection for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’sa second time. Upon emergence from this second bankruptcy, plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets willare to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
By letter dated April 5, 2022 replacing(replacing two prior letters dated September 8, 2021 and February 22, 2022,earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currentlywas obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
20


As of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.”
On June 21, 2023, the two sureties that issued bondsBonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seekingThe sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further allegealleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). which subsequently held that the sureties’ state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is void. Since the time the sureties filed their state court lawsuit, Apache intendshas drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. Apache is vigorously defendpursuing its claims against the sureties.
As of March 31, 2024, the Company has recorded a $186 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these claims,decommissioning costs.
The Company has recorded contingent liabilities in the amounts of $847 million and will vigorously pursue its counterclaims.$824 million as of March 31, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on legacy GOM properties previously sold to Fieldwood and other GOM operators. During the first quarter of 2024, the Company recognized $66 million of “Loss on previously sold Gulf of Mexico properties,” which includes increases of $33 million related to orders received during the period from BSEE to decommission properties previously sold to Cox Operating LLC. The Company recognized no losses for decommissioning previously sold properties during the first quarter of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.
2119


12.    CAPITAL STOCK
Net Income per Common Share
The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements:
For the Quarter Ended March 31,
20242023
For the Quarter Ended September 30, IncomeSharesPer ShareIncomeSharesPer Share
20232022
IncomeSharesPer ShareIncomeSharesPer Share
(In millions, except per share amounts)(In millions, except per share amounts)
Basic:Basic:
Income attributable to common stockIncome attributable to common stock$459 308 $1.49 $422 329 $1.28 
Income attributable to common stock
Income attributable to common stock
Effect of Dilutive Securities:Effect of Dilutive Securities:
Stock options and other$— — $— $— $— 
Stock compensation awards
Stock compensation awards
Stock compensation awards
Diluted:Diluted:
Diluted:
Diluted:
Income attributable to common stock
Income attributable to common stock
Income attributable to common stockIncome attributable to common stock$459 308 $1.49 $422 330 $1.28 
For the Nine Months Ended September 30,
20232022
IncomeSharesPer ShareIncomeSharesPer Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock$1,082 309 $3.50 $3,231 339 $9.54 
Effect of Dilutive Securities:
Stock options and other$— — $— $— $(0.03)
Diluted:
Income attributable to common stock$1,082 309 $3.50 $3,231 340 $9.51 
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 1.72.1 million and 2.1 million during the third quarters of 2023 and 2022, respectively, and 2.0 million and 2.52.4 million during the first nine monthsquarters of 20232024 and 2022,2023, respectively.
Stock Repurchase Program
During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors further authorized the purchase of an additional 40 million shares of the Company's common stock.
In the thirdfirst quarter of 2023,2024, the Company repurchased approximately 0.53.0 million shares at an average price of $41.90 per share. For the nine months ended September 30, 2023, the Company repurchased 5.5 million shares at an average price of $37.91$33.27 per share, and as of September 30, 2023,March 31, 2024, the Company had remaining authorization to repurchase up to 47.140.9 million shares. The repurchases were partially financed by APA’s borrowing under its US dollar-denominated revolving credit facility. In the thirdfirst quarter of 2022,2023, the Company repurchased 9.83.7 million shares at an average price of $33.86$38.93 per share. For the nine months ended September 30, 2022, the Company repurchased 24 million shares at an average price of $36.78 per share.
The Company repurchased 0.4 million shares at an average price of $40.26 per share in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares.
The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately negotiated transactions.
Common Stock Dividend
For the quarters ended September 30,March 31, 2024 and 2023, and 2022, the Company paid $77$76 million and $41 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2023 and 2022, the Company paid $232 million and $127$78 million, respectively, in dividends on its common stock.
22


During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.
2320


13.    BUSINESS SEGMENT INFORMATION
As of September 30, 2023,March 31, 2024, the Company’s consolidated subsidiaries are engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S., Egypt, and North Sea. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic,Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:
U.S.U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)
Egypt(1)
North SeaU.S.Altus MidstreamIntersegment
Eliminations
& Other
Total
For the Quarter Ended March 31, 2024
UpstreamAltus MidstreamIntersegment
Eliminations
& Other
Total
For the Quarter Ended March 31, 2024
For the Quarter Ended September 30, 2023(In millions)
For the Quarter Ended March 31, 2024(In millions)
Revenues:Revenues:
Oil revenues
Oil revenues
Oil revenuesOil revenues$724 $348 $633 $— $— $1,705 
Natural gas revenuesNatural gas revenues81 66 89 — — 236 
Natural gas liquids revenuesNatural gas liquids revenues— 133 — — 138 
Oil, natural gas, and natural gas liquids production revenuesOil, natural gas, and natural gas liquids production revenues805 419 855 — — 2,079 
Purchased oil and gas salesPurchased oil and gas sales— — 229 — — 229 
805 419 1,084 — — 2,308 
979
979
979
Operating Expenses:Operating Expenses:
Lease operating expenses
Lease operating expenses
Lease operating expensesLease operating expenses128 102 164 — — 394 
Gathering, processing, and transmissionGathering, processing, and transmission13 15 61 — — 89 
Purchased oil and gas costsPurchased oil and gas costs— — 211 — — 211 
Taxes other than incomeTaxes other than income— — 61 — — 61 
ExplorationExploration25 — 11 49 
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization129 90 199 — — 418 
Asset retirement obligation accretionAsset retirement obligation accretion— 20 — — 29 
295 236 709 — 11 1,251 
723
723
723
Operating Income (Loss)(2)
Operating Income (Loss)(2)
$510 $183 $375 $— $(11)1,057 
Other Income (Expense):Other Income (Expense):
Other Income (Expense):
Other Income (Expense):
Derivative instrument losses, net
Derivative instrument losses, net
Derivative instrument losses, net
Loss on previously sold Gulf of Mexico properties
Gain on divestitures, netGain on divestitures, net
Other, net
General and administrativeGeneral and administrative(139)
Transaction, reorganization, and separationTransaction, reorganization, and separation(5)
Financing costs, netFinancing costs, net(81)
Income Before Income TaxesIncome Before Income Taxes$833 
Total Assets(3)
Total Assets(3)
Total Assets(3)

2421



Egypt(1)
North SeaU.S.Altus MidstreamIntersegment
Eliminations
& Other
Total(4)
Upstream
For the Nine Months Ended September 30, 2023(In millions)
Revenues:
Oil revenues$1,971 $865 $1,631 $— $— $4,467 
Natural gas revenues264 165 229 — — 658 
Natural gas liquids revenues— 19 356 — — 375 
Oil, natural gas, and natural gas liquids production revenues2,235 1,049 2,216 — — 5,500 
Purchased oil and gas sales— — 612 — — 612 
2,235 1,049 2,828 — — 6,112 
Operating Expenses:
Lease operating expenses346 278 452 — — 1,076 
Gathering, processing, and transmission26 38 181 — — 245 
Purchased oil and gas costs— — 558 — — 558 
Taxes other than income— — 163 — — 163 
Exploration91 18 10 — 25 144 
Depreciation, depletion, and amortization378 209 530 — — 1,117 
Asset retirement obligation accretion— 57 29 — — 86 
Impairments— 46 — — — 46 
841 646 1,923 — 25 3,435 
Operating Income (Loss)(2)
$1,394 $403 $905 $— $(25)2,677 
Other Income (Expense):
Derivative instrument gains, net104 
Gain on divestitures, net
Other, net77 
General and administrative(276)
Transaction, reorganization, and separation(11)
Financing costs, net(235)
Income Before Income Taxes$2,343 
Total Assets(3)
$3,518 $1,665 $7,827 $— $535 $13,545 

25


Egypt(1)
North SeaU.S.Altus MidstreamIntersegment
Eliminations
& Other
Total(4)
Upstream
For the Quarter Ended September 30, 2022(In millions)
Revenues:
Oil revenues$739 $303 $630 $— $— $1,672 
Natural gas revenues84 44 300 — — 428 
Natural gas liquids revenues— 197 — — 202 
Oil, natural gas, and natural gas liquids production revenues823 352 1,127 — — 2,302 
Purchased oil and gas sales— — 585 — — 585 
823 352 1,712 — — 2,887 
Operating Expenses:
Lease operating expenses119 107 138 — — 364 
Gathering, processing, and transmission87 — — 99 
Purchased oil and gas costs— — 573 — — 573 
Taxes other than income— — 82 — — 82 
Exploration29 16 — 49 95 
Depreciation, depletion, and amortization97 52 161 — — 310 
Asset retirement obligation accretion— 21 — — 29 
250 188 1,065 — 49 1,552 
Operating Income (Loss)(2)
$573 $164 $647 $— $(49)1,335 
Other Income (Expense):
Derivative instrument losses, net(44)
Gain on divestitures, net31 
Other, net(2)
General and administrative(69)
Transaction, reorganization, and separation(4)
Financing costs, net(75)
Income Before Income Taxes$1,172 
26


U.S.U.S.
Egypt(1)
North SeaIntersegment
Eliminations
& Other
Total(4)


Egypt(1)
North SeaU.S.Altus MidstreamIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended March 31, 2023
UpstreamAltus MidstreamIntersegment
Eliminations
& Other
Total(4)
For the Quarter Ended March 31, 2023
For the Nine Months Ended September 30, 2022(In millions)
For the Quarter Ended March 31, 2023(In millions)
Revenues:Revenues:
Oil revenues
Oil revenues
Oil revenuesOil revenues$2,431 $938 $1,883 $— $— $5,252 
Natural gas revenuesNatural gas revenues270 207 764 — — 1,241 
Natural gas liquids revenuesNatural gas liquids revenues33 618 — (3)654 
Oil, natural gas, and natural gas liquids production revenuesOil, natural gas, and natural gas liquids production revenues2,707 1,178 3,265 — (3)7,147 
Purchased oil and gas salesPurchased oil and gas sales— — 1,451 — 1,456 
Midstream service affiliate revenues— — — 16 (16)— 
2,707 1,178 4,716 21 (19)8,603 
934
Operating Expenses:Operating Expenses:
Lease operating expenses
Lease operating expenses
Lease operating expensesLease operating expenses381 321 366 — (1)1,067 
Gathering, processing, and transmissionGathering, processing, and transmission15 31 241 (18)274 
Purchased oil and gas costsPurchased oil and gas costs— — 1,452 — — 1,452 
Taxes other than incomeTaxes other than income— — 227 — 230 
ExplorationExploration56 21 — 108 193 
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization285 168 424 — 879 
Asset retirement obligation accretionAsset retirement obligation accretion— 61 25 — 87 
737 589 2,756 11 89 4,182 
639
639
639
Operating Income (Loss)(2)
Operating Income (Loss)(2)
$1,970 $589 $1,960 $10 $(108)4,421 
Other Income (Expense):Other Income (Expense):
Derivative instrument losses, net(138)
Other Income (Expense):
Other Income (Expense):
Derivative instrument gains, net
Derivative instrument gains, net
Derivative instrument gains, net
Gain on divestitures, netGain on divestitures, net1,180 
Other, netOther, net107 
General and administrativeGeneral and administrative(314)
Transaction, reorganization, and separationTransaction, reorganization, and separation(21)
Financing costs, netFinancing costs, net(303)
Income Before Income TaxesIncome Before Income Taxes$4,932 
Total Assets(3)
Total Assets(3)
$3,242 $2,185 $7,675 $— $527 $13,629 
Total Assets(3)
Total Assets(3)
(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the quarters ended March 31, 2024 and nine months ended September 30, 2023 and 2022 of:
For the Quarter Ended March 31,
For the Quarter Ended March 31,
For the Quarter Ended March 31,
For the Quarter Ended September 30,For the Nine Months Ended September 30,
2023202220232022
(In millions)
(In millions)
(In millions)
(In millions)
OilOil$202 $227 $539 $779 
Natural gasNatural gas23 26 73 87 
Natural gas liquids— — — 
Natural gas
Natural gas
(2)Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $2$10 million $6 million, and $1 million, respectively, for the thirdfirst quarter of 2023.2024.
Operating income of U.S. and EgyptNorth Sea includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022. Operating income of U.S., North Sea, and Suriname includes leasehold impairments of $7 million, $12 million, and $1 million, respectively, for the first nine months of 2023. Operating income of U.S. and Egypt includes leasehold impairments of $19$2 million and $3 million, respectively, for the first nine monthsquarter of 2022.2023.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests in Egypt and in Altus prior to deconsolidation.Egypt.

2722


ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023.
Overview
APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has explorationoil and productiongas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic,Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries. Prior to the BCP Business Combination (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).
APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.
The global economy and the energy industry continue to be impacted by the effects of ongoing international conflicts and the coronavirus disease 2019 (COVID-19) pandemic. Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of activities offshore Suriname; (2) to invest for long-term returns overin pursuit of moderate, sustainable production growth; and (3)(2) to budget conservativelystrengthen the balance sheet to generateunderpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continuesshareholders; and (3) to aggressivelyresponsibly manage its cost structure regardless of the oil price environment andenvironment.
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.
APA’s diversified asset portfolio and operational flexibility provide itthe Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. The Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices during the year but are accelerating completion of eight Permian Basin wells and adding a drilling rig in the Delaware Basin in the fourth quarter of 2023. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. The Company anticipates its full-year 2023 upstream capital investment will be approximately $2 billion. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.
In the third quarter of 2023, the Company reported net income attributable to common stock of $459 million, or $1.49 per diluted share, compared to net income of $422 million, or $1.28 per diluted share, in the third quarter of 2022. Results for the third quarter of 2022 were impacted by higher deferred income tax expense related to remeasurement of the Company’s deferred tax liability from increases in the U.K. energy profits levy.
In the first nine months of 2023, the Company reported net income attributable to common stock of $1.1 billion, or $3.50 per diluted share, compared to net income of $3.2 billion, or $9.51 per diluted share, in the first nine months of 2022. Net income for the first nine months of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the first nine months of 2022. Results from the first nine months of 2022 included approximately $1.2 billion of transaction gains recognized for divesting certain non-core mineral rights in the Delaware Basin and completing the BCP Business Combination.
28


The Company generated $2.1 billion of cash from operating activities during the first nine months of 2023, 41 percent lower than the first nine months of 2022. APA’s lower operating cash flows for the first nine months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 5.5 million shares of its common stock for $208 million and paid $232 million in dividends to APA common stockholders during the first nine months of 2023.
The Company remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns.
The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
The Company’s quarterly dividend was increased in the third quarter of 2022 from $0.125 per share to $0.25 per share, representing a return to pre-COVID-19 dividend levels.share.
Beginning in the fourth quarter of 2021 and through the end of the thirdfirst quarter of 2023,2024, the Company hadhas repurchased 72.979.1 million shares of the Company’s common stock.
Financial and Operational Highlights
In the first quarter of 2024, the Company reported net income attributable to common stock of $132 million, or $0.44 per diluted share, compared to net income of $242 million, or $0.78 per diluted share, in the first quarter of 2023. Results for the first quarter of 2024 compared to the first quarter of 2023 were primarily impacted by higher DD&A and dry hole expense and an upward revision on decommissioning costs for its previously sold Gulf of Mexico assets in the current-year period, partially offset by lower deferred income tax expense.
The Company generated $368 million of cash from operating activities during the first three months of 2024, 10 percent higher than the first three months of 2023. APA’s higher operating cash flows for the first three months of 2024 were primarily driven by timing of working capital items. The Company repurchased 0.43.0 million shares of its common stock for $101 million and paid $76 million in Octoberdividends to APA common stockholders during the first three months of 2024.
23


On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The transaction was approved by APA and Callon shareholders at special meetings held on March 27, 2024. The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. Callon’s fourth-quarter 2023 production was 103,000 BOE per day, comprising 58 percent oil and as80 percent liquids.
Subject to the terms of October 31, 2023, the Company had remaining authorizationmerger agreement, each share of Callon common stock was converted into the right to repurchase up to 46.7receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares underof APA common stock in connection with the Company’s share repurchase programs.
Operational Highlightstransaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.
Key operational highlights for the quarter include:
United States
Daily boe production from the Company’s U.S. assets accounted for 55 percent of its total production during the thirdfirst quarter of 2024 and increased 6 percent from the first quarter of 2023. TheDaily oil production from the Company’s U.S. assets increased 16 percent from the first quarter of 2023. During the first quarter of 2024, the Company averaged fivesix drilling rigs in the U.S. during the quarter,, including three rigs in the Southern Midland Basin and twothree rigs in the Delaware Basin, and drilled and brought online 1512 operated wells in the quarter. The Company has contracted a sixth Permian Basin rig, with plans to commence drilling in the fourth quarter of 2023. The Company’s core MidlandPermian Basin development program and recently acquired properties in the Delaware Basin continuecontinues to represent key growth areas for the U.S. assets.
The Company expects to average 10 drilling rigs in the U.S. for the remainder of 2024 as it integrates Callon operations, including contracting and logistics, well planning and design, drilling and completions, and facility construction.
International
In Egypt, the Company continued its drilling and workover activity with a heavier focus on oil prospects.production. The Company averaged 1817 drilling rigs and drilled 2617 new productive wells during the thirdfirst quarter of 2023. Third2024. During the same period, the Company averaged 21 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. First quarter 20232024 gross and net equivalent production in the Company’s Egypt assets increased 2decreased 8 percent from the thirdfirst quarter of 2022, and net2023, while daily oil production decreased 3 percent. The Company averaged 20 workover rigs during the quarter and expects to increase workover activity over the next two quarters.remained essentially flat.
The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program therein the North Sea is now directed toward safety, base production management, and asset maintenance and integrity.
During the quarter, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58, offshore Suriname. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an oil production capacity of 200,000 b/d. Detailed engineering studies are anticipated to start by year-end 2023, and a final investment decision is expected by year-end 2024 with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.

2924


Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Production Revenues
Revenue
The Company’s production revenues and respective contribution to total revenues by country were as follows:
$ Value
$ Value
$ Value
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
$ Value%
Contribution
$ Value%
Contribution
$ Value%
Contribution
$ Value%
Contribution
($ in millions)($ in millions)
Oil Revenues:Oil Revenues:
United StatesUnited States$633 37 %$630 38 %$1,631 37 %$1,883 36 %
United States
United States
Egypt(1)
Egypt(1)
Egypt(1)
Egypt(1)
724 43 %739 44 %1,971 44 %2,431 46 %
North SeaNorth Sea348 20 %303 18 %865 19 %938 18 %
North Sea
North Sea
Total(1)
Total(1)
Total(1)
Total(1)
$1,705 100 %$1,672 100 %$4,467 100 %$5,252 100 %
Natural Gas Revenues:Natural Gas Revenues:
Natural Gas Revenues:
Natural Gas Revenues:
United States
United States
United StatesUnited States$89 38 %$300 70 %$229 35 %$764 62 %
Egypt(1)
Egypt(1)
81 34 %84 20 %264 40 %270 22 %
Egypt(1)
Egypt(1)
North SeaNorth Sea66 28 %44 10 %165 25 %207 16 %
North Sea
North Sea
Total(1)
Total(1)
Total(1)
Total(1)
$236 100 %$428 100 %$658 100 %$1,241 100 %
NGL Revenues:NGL Revenues:
NGL Revenues:
NGL Revenues:
United StatesUnited States$133 96 %$197 98 %$356 95 %$615 94 %
Egypt(1)
— — %— — %— — %%
United States
United States
North SeaNorth Sea%%19 %33 %
North Sea
North Sea
Total(1)
Total(1)
Total(1)
Total(1)
$138 100 %$202 100 %$375 100 %$654 100 %
Oil and Gas Revenues:Oil and Gas Revenues:
Oil and Gas Revenues:
Oil and Gas Revenues:
United States
United States
United StatesUnited States$855 41 %$1,127 49 %$2,216 40 %$3,262 46 %
Egypt(1)
Egypt(1)
805 39 %823 36 %2,235 41 %2,707 38 %
Egypt(1)
Egypt(1)
North Sea
North Sea
North SeaNorth Sea419 20 %352 15 %1,049 19 %1,178 16 %
Total(1)
Total(1)
$2,079 100 %$2,302 100 %$5,500 100 %$7,147 100 %
Total(1)
Total(1)
(1)    Includes revenues attributable to a noncontrolling interest in Egypt.

3025


Production
The Company’s production volumes by country were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023Increase
(Decrease)
20222023Increase
(Decrease)
2022
2024
2024
2024
Oil Volume (b/d)
Oil Volume (b/d)
Oil Volume (b/d)Oil Volume (b/d)
United StatesUnited States83,584 16%72,351 77,198 12%68,926 
United States
United States
Egypt(1)(2)
Egypt(1)(2)
Egypt(1)(2)
Egypt(1)(2)
88,521 9%81,095 88,038 5%83,857 
North SeaNorth Sea35,680 42%25,160 36,070 17%30,928 
North Sea
North Sea
Total
Total
TotalTotal207,785 16%178,606 201,306 10%183,711 
Natural Gas Volume (Mcf/d)Natural Gas Volume (Mcf/d)
Natural Gas Volume (Mcf/d)
Natural Gas Volume (Mcf/d)
United States
United States
United StatesUnited States454,643 (7)%489,107 448,838 (5)%474,777 
Egypt(1)(2)
Egypt(1)(2)
300,326 (6)%318,945 331,158 (5)%350,400 
Egypt(1)(2)
Egypt(1)(2)
North SeaNorth Sea65,168 246%18,822 47,665 43%33,291 
North Sea
North Sea
Total
Total
TotalTotal820,137 (1)%826,874 827,661 (4)%858,468 
NGL Volume (b/d)NGL Volume (b/d)
NGL Volume (b/d)
NGL Volume (b/d)
United StatesUnited States66,280 2%64,958 61,418 (1)%61,990 
Egypt(1)(2)
— NM— — NM261 
United States
United States
North SeaNorth Sea1,497 168%558 1,209 12%1,080 
North Sea
North Sea
Total
Total
TotalTotal67,777 3%65,516 62,627 (1)%63,331 
BOE per day(3)
BOE per day(3)
BOE per day(3)
BOE per day(3)
United States
United States
United StatesUnited States225,639 3%218,826 213,423 2%210,045 
Egypt(1)(2)
Egypt(1)(2)
138,575 3%134,253 143,231 1%142,518 
Egypt(1)(2)
Egypt(1)(2)
North Sea(4)
North Sea(4)
North Sea(4)
North Sea(4)
48,038 66%28,855 45,222 20%37,557 
TotalTotal412,252 8%381,934 401,876 3%390,120 
Total
Total
(1)    Gross oil, natural gas, and NGL production in Egypt were as follows:
For the Quarter Ended March 31,
For the Quarter Ended March 31,
For the Quarter Ended March 31,
For the Quarter Ended September 30,For the Nine Months Ended September 30,
2023202220232022
Oil (b/d)Oil (b/d)144,528 133,607 141,995 136,476 
Oil (b/d)
Oil (b/d)
Natural Gas (Mcf/d)Natural Gas (Mcf/d)472,744 510,260 511,430 554,268 
NGL (b/d)— — — 397 
Natural Gas (Mcf/d)
Natural Gas (Mcf/d)
(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 March 31,
For the Quarter Ended March 31,
For the Quarter Ended September 30,For the Nine Months Ended September 30,
2023202220232022
Oil (b/d)Oil (b/d)29,514 27,082 29,369 27,971 
Oil (b/d)
Oil (b/d)
Natural Gas (Mcf/d)Natural Gas (Mcf/d)100,122 106,553 110,476 116,869 
NGL (b/d)— — — 87 
Natural Gas (Mcf/d)
Natural Gas (Mcf/d)
(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 thirdfirst quarters of 2024 and 2023 and 2022 were 55,28335,078 boe/d and 36,46746,632 boe/d, respectively, and 47,370 boe/d and 39,362 boe/d for the first nine months of 2023 and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
NM — Not Meaningful

3126


Pricing
The Company’s average selling prices by country were as follows:
 
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023Increase
(Decrease)
20222023Increase
(Decrease)
2022
Average Oil Price – Per barrel
United States$82.33 (13)%$94.62 $77.40 (23)%$100.06 
Egypt88.99 (10)%99.04 82.04 (23)%106.19 
North Sea87.70 (14)%101.85 83.25 (21)%105.59 
Total86.15 (12)%97.81 80.50 (22)%103.81 
Average Natural Gas Price – Per Mcf
United States$2.12 (68)%$6.67 $1.87 (68)%$5.89 
Egypt2.91 1%2.87 2.92 4%2.82 
North Sea10.98 (54)%24.12 12.83 (48)%24.59 
Total3.12 (44)%5.62 2.91 (45)%5.31 
Average NGL Price – Per barrel
United States$21.87 (34)%$32.97 $21.24 (42)%$36.36 
Egypt— NM— — NM76.80 
North Sea42.78 (39)%70.42 47.58 (35)%72.86 
Total22.26 (33)%33.39 21.85 (42)%37.47 
NM — Not Meaningful
 
For the Quarter Ended
March 31,
2024Increase
(Decrease)
2023
Average Oil Price – Per barrel
United States$77.37 3%$75.17 
Egypt83.18 5%79.58 
North Sea82.81 2%81.57 
Total80.65 3%78.37 
Average Natural Gas Price – Per Mcf
United States$1.42 (37)%$2.24 
Egypt2.93 1%2.89 
North Sea9.23 (47)%17.58 
Total2.47 (23)%3.22 
Average NGL Price – Per barrel
United States$25.38 7%$23.79 
North Sea49.37 (13)%56.92 
Total26.20 5%24.84 
Third-Quarter 2023First-Quarter 2024 compared to Third-Quarter 2022First-Quarter 2023
Crude Oil Crude oil revenues for the thirdfirst quarter of 20232024 totaled $1.7$1.4 billion, a $33$35 million increase from the comparative 20222023 quarter. A 163 percent higher average daily production increased revenues by $233 million compared to the prior-year quarter, while 12 percent decreaseincrease in average realized prices decreased third-quarter 2023primarily drove the increase in crude oil revenues by $200 million.compared to the first quarter of 2023. Crude oil revenues accounted for 82 percent of total oil and gas production revenues and 5051 percent of worldwide production in the thirdfirst quarter of 2023.2024. Crude oil prices realized in the thirdfirst quarter of 20232024 averaged $86.15$80.65 per barrel, compared with $97.81$78.37 per barrel in the comparative prior-year quarter.
The Company’s worldwide oil production increased 29.22.9 Mb/d to 207.8200.1 Mb/d during the thirdfirst quarter of 20232024 from the comparative prior-year period, primarily a result of increased drilling activity in the U.S. and Egypt, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline across all assets.
Natural Gas Gas revenues for the third quarter of 2023 totaled $236 million, a $192 million decrease from the comparative 2022 quarter. A 44 percent decrease in average realized prices decreased third-quarter 2023 natural gas revenues by $191 million compared to the prior-year quarter, while 1 percent lower average daily production decreased revenues by $1 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2023. The Company’s worldwide natural gas production decreased 6.8 MMcf/d to 820.1 MMcf/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., offset by increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea.
NGL NGL revenues for the third quarter of 2023 totaled $138 million, a $64 million decrease from the comparative 2022 quarter. A 33 percent decrease in average realized prices decreased third-quarter 2023 NGL revenues by $67 million compared to the prior-year quarter, while 3 percent higher average daily production increased revenues by $3 million. NGL revenues accounted for 7 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2023. The Company’s worldwide NGL production increased 2.3 Mb/d to 67.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline.
32


Year-to-Date 2023 compared to Year-to-Date 2022
Crude Oil Crude oil revenues for the first nine months of 2023 totaled $4.5 billion, a $785 million decrease from the comparative 2022 period. A 22 percent decrease in average realized prices decreased oil revenues for the 2023 period by approximately $1.2 billion compared to the prior-year period, while 10 percent higher average daily production increased revenues by $394 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2023. Crude oil prices realized during the first nine months of 2023 averaged $80.50 per barrel, compared to $103.81 per barrel in the comparative prior-year period.
The Company’s worldwide oil production increased 17.6 Mb/d to 201.3 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.
Natural Gas Gas revenues for the first nine monthsquarter of 20232024 totaled $658$176 million, a $583$66 million decrease from the comparative 2022 period.2023 quarter. A 4523 percent decrease in average realized prices decreased first-quarter 2024 natural gas revenues for the 2023 period by $560$56 million compared to the prior-year period,quarter, while 46 percent lower average daily production decreased revenues by $23 million compared to the prior-year period.$10 million. Natural gas revenues accounted for 1210 percent of total oil and gas production revenues and 34 percent of worldwide production forduring the first nine monthsquarter of 2023.2024. The Company’s worldwide natural gas production decreased 30.851.7 MMcf/d to 827.7786.6 MMcf/d induring the first nine monthsquarter of 2023 compared to2024 from the comparative prior-year period, primarily a result of natural production decline across all assets, reduced gas-focused activity in Egypt, and the salecurtailment of non-core assetsvolumes at Alpine High in the U.S.,response to extreme Waha basis differentials. These decreases were partially offset by increased drilling activity and recompletions property acquisitions in the U.S., and less maintenance downtime in the North Sea.
NGLNGL revenues for the first nine monthsquarter of 20232024 totaled $375$140 million, a $279$10 million decreaseincrease from the comparative 2022 period.2023 quarter. A 425 percent decreaseincrease in average realized prices decreasedincreased first-quarter 2024 NGL revenues for the 2023 period by $273$7 million compared to the prior-year period,quarter, while 1 percent lowerhigher average daily production decreasedincreased revenues by $6 million compared to the prior-year period.$3 million. NGL revenues accounted for 78 percent of total oil and gas production revenues and 1615 percent of worldwide production forduring the first nine monthsquarter of 2023.2024. The Company’s worldwide NGL production decreased 0.7increased 0.6 Mb/d to 6358.0 Mb/d induring the first nine monthsquarter of 2023 compared to2024 from the comparative prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.
27


Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basinU.S. domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations.obligations and delivery commitments. Sales related to these purchased volumes totaled $229$203 million and $585$239 million during the thirdfirst quarters of 20232024 and 2022, respectively, and $612 million and $1.5 billion during the first nine months of 2023, and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $211$163 million and $573$216 million during the thirdfirst quarters of 20232024 and 2022, respectively, and $558 million and $1.5 billion during the first nine months of 2023, and 2022, respectively. Gross purchased oil and gas sales values were lower in the thirdfirst quarter and the first nine months of 2023,2024, primarily due to lower average natural gas prices during the 2023 periods.first quarter of 2024, as compared to the first quarter of 2023.
33


Operating Expenses
The Company’s operating expenses were as follows:follows and include costs attributable to a noncontrolling interest in Egypt:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)(In millions)
Lease operating expensesLease operating expenses$394 $364 $1,076 $1,067 
Gathering, processing, and transmissionGathering, processing, and transmission89 99 245 274 
Gathering, processing, and transmission
Gathering, processing, and transmission
Purchased oil and gas costs
Purchased oil and gas costs
Purchased oil and gas costsPurchased oil and gas costs211 573 558 1,452 
Taxes other than incomeTaxes other than income61 82 163 230 
Taxes other than income
Taxes other than income
Exploration
Exploration
ExplorationExploration49 95 144 193 
General and administrativeGeneral and administrative139 69 276 314 
General and administrative
General and administrative
Transaction, reorganization, and separation
Transaction, reorganization, and separation
Transaction, reorganization, and separationTransaction, reorganization, and separation11 21 
Depreciation, depletion, and amortization:Depreciation, depletion, and amortization:
Depreciation, depletion, and amortization:
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Oil and gas property and equipment
Oil and gas property and equipmentOil and gas property and equipment407 300 1,086 847 
Gathering, processing, and transmission assetsGathering, processing, and transmission assets10 
Gathering, processing, and transmission assets
Gathering, processing, and transmission assets
Other assets
Other assets
Other assetsOther assets26 22 
Asset retirement obligation accretionAsset retirement obligation accretion29 29 86 87 
Impairments— — 46 — 
Asset retirement obligation accretion
Asset retirement obligation accretion
Financing costs, net
Financing costs, net
Financing costs, netFinancing costs, net81 75 235 303 
Total Operating ExpensesTotal Operating Expenses$1,476 $1,700 $3,957 $4,820 
Total Operating Expenses
Total Operating Expenses
Lease Operating Expenses (LOE)
LOE increased $30 million and $9$17 million compared to the thirdfirst quarter and the first nine months of 2022, respectively.2023. On a per-unit basis, LOE remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased 2increased 7 percent in the first nine monthsquarter of 20232024 when compared to the first nine monthsquarter of 2022.2023. Overall higher labor costs and other operating costs trending with global inflation drove an increase in absolute LOE, but these increases were primarilypartially offset by decreased workover activity primarily in the North SeaU.S. and changes in foreign currency exchange rates against the US dollar.
Gathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)
Third-party processing and transmission costs$63 $71 $164 $205 
Midstream service costs – ALTM�� — — 18 
Midstream service costs – Kinetik26 28 81 64 
Upstream processing and transmission costs89 99 245 287 
Midstream operating expenses— — — 
Intersegment eliminations— — — (18)
Total Gathering, processing, and transmission$89 $99 $245 $274 
For the Quarter Ended
March 31,
20242023
(In millions)
Third-party processing and transmission costs$61 $52 
Midstream service costs – Kinetik23 26 
Total Gathering, processing, and transmission$84 $78 
GPT costs decreased $10 million and $29increased $6 million in the thirdfirst quarter andof 2024 when compared to the first nine monthsquarter of 2023, respectively, from the comparative prior-year period, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $10 million and $42 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily driven by a decreaseslight increase in natural gas production volumes in the U.S. when compared to the prior-year period.
Purchased Oil and Gas Costs for services provided by ALTM
Purchased oil and gas costs decreased $53 million in 2022 priorthe first quarter of 2024, to $163 million from $216 million in the first quarter of 2023. The decrease is a result of lower average natural gas prices in the first quarter of 2024 compared to the BCP Business Combinationfirst quarter of 2023. Purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $18$203 million were eliminated in the Company’s consolidated financial statements and reflectedfirst quarter of 2024, as “Intersegment eliminations” in the tablediscussed above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated.
3428


Taxes Other Than Income
Taxes other than income decreased $21 million and $67increased $5 million from the thirdfirst quarter and the first nine months of 2022, respectively,2023, primarily from lowerhigher severance taxes driven by lower commodityincreased production volumes and higher oil prices asin the U.S. compared to the prior-year periods.period.
Exploration Expenses
The Company’s exploration expenses were as follows:
For the Quarter Ended
March 31,
For the Quarter Ended
March 31,
For the Quarter Ended
March 31,
2024
2024
2024
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
(In millions)
2023202220232022
(In millions)
(In millions)
(In millions)
Unproved leasehold impairmentsUnproved leasehold impairments$$16 $20 $22 
Dry hole expenseDry hole expense18 66 71 107 
Dry hole expense
Dry hole expense
Geological and geophysical expense
Geological and geophysical expense
Geological and geophysical expenseGeological and geophysical expense19 
Exploration overhead and otherExploration overhead and other21 12 50 45 
Exploration overhead and other
Exploration overhead and other
Total ExplorationTotal Exploration$49 $95 $144 $193 
Total Exploration
Total Exploration
Exploration expenses decreased $46 million and $49increased $96 million from the thirdfirst quarter and the first nine months of 2022, respectively,2023, primarily the result of higher dry hole expensethe completion of an initial drilling campaign in Suriname and Egypt during 2022 coupled with lower geological and geophysical expenses. These decreasesAlaska where two wells were partially offset by higher exploration overhead and other activities.unable to reach target objectives in the allotted seasonal time window.
General and Administrative (G&A) Expenses
G&A expenses increased $70 million and decreased $38$28 million compared to the thirdfirst quarter and the first nine months of 2022, respectively.2023. The increase in G&A expenses for the thirdfirst quarter of 20232024 compared to the thirdfirst quarter of 20222023 was primarily driven by higher overall labor costs across the Company and higher cash-based stock compensation expense resulting from changes in the Company’s stock price and anticipated achievement of performance and financial objectives as defined in the stock award plans. G&A expenses for the first nine months of 2022 were higher than the first nine months of 2023, as impacts of anticipated achievement-based objectives and changes in the Company’s stock price on cash-based stock compensation were greater during the first nine months of 2022 than those in the first nine months of 2023.price.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs remained essentially flat inincreased $23 million from the thirdfirst quarter of 2023 when compared to the third quarter of 2022 and decreased $10 million compared to the first nine months of 2022.2023. Higher TRS costs during the first nine monthsquarter of 20222024 were primarily a result of ongoing transaction costs fromrelated to the BCP Business CombinationCallon acquisition coupled with separation costs in the firstNorth Sea. The Company expects to incur an additional $90 million of TSR costs related to the Callon merger. A majority of these costs will be incurred in the second quarter of 2022.for professional services, departing Callon employees, and other closing costs.
Depreciation, Depletion, and Amortization (DD&A)
Total DD&A expenses increased $108 million and $238$98 million from the thirdfirst quarter and the first nine months of 2022, respectively,2023, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $2.17 per boe and $1.93$2.86 per boe from the thirdfirst quarter andof 2023 driven primarily by price-related negative reserve revisions over the first nine months of 2022, respectively, driven by general cost inflation.prior 12 months. The increase on an absolute basis was also impacted by an increase inhigher oil and gas property balances resulting from capital investment activity in Egypt and acquisitions in the U.S. over the past year.
Impairments
During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
3529


Financing Costs, Net
The Company’s Financing costs were as follows:
For the Quarter Ended
September 30,
For the Nine Months Ended
September 30,
2023202220232022
(In millions)(In millions)
Interest expenseInterest expense$89 $80 $266 $249 
Amortization of debt issuance costsAmortization of debt issuance costs
Amortization of debt issuance costs
Amortization of debt issuance costs
Capitalized interestCapitalized interest(7)(5)(18)(13)
(Gain) loss on extinguishment of debt— — (9)67 
Capitalized interest
Capitalized interest
Gain on extinguishment of debt
Gain on extinguishment of debt
Gain on extinguishment of debt
Interest income
Interest income
Interest incomeInterest income(2)(1)(7)(8)
Total Financing costs, netTotal Financing costs, net$81 $75 $235 $303 
Total Financing costs, net
Total Financing costs, net
Net financing costs increased $6 million and decreased $68$4 million from the thirdfirst quarter and the first nine months of 2022, respectively.2023. The increase in costs during the thirdfirst quarter of 20232024 was primarily a result of interest expense on higher outstanding credit facility borrowings compared to the prior-year period. The decrease in costs during the first nine months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first nine months of 2022 and gains on extinguishment of debt inrecorded during the first nine monthsquarter of 2023,2023. The increase was partially offset by lower interest expense on higher outstanding credit facility borrowingsfrom lower average long-term debt balances during the first quarter of 2024 compared to the prior-yearsame prior year period.
Provision for Income Taxes
The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
During the third quarter of 2023, theThe Company’s effective income tax rate was primarily impacted by a decrease infor the amountthree months ended March 31, 2024 differed from the U.S. federal statutory income tax rate of valuation allowance against its U.S. deferred tax assets.21 percent due to taxes on foreign operations. The Company’s 2023 year-to-date effective income tax rate was primarily impacted byfor the three months ended March 31, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent,In December 2021, the Organisation for Economic Co-operation and included amendments to the Energy (Oil and Gas) Profits Levy ActDevelopment issued Pillar Two Model Rules introducing a new global minimum tax of 2022, increasing the levy from15 percent on a 25 percent rate to a 35 percent rate,country-by-country basis, with certain aspects effective for the period ofin certain jurisdictions on 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 2023,2024. Although the Company recorded a deferred tax expense of $174 million relatedcontinues to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S.monitor 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 continuinglegislation to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact ofimplement these provisions on the Company. Under the existing guidance,rules in countries where the Company could be impacted, APA does not believeexpect that the IRAPillar Two framework will have a material impact for 2023.
The Company has a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.
36


consolidated financial statements.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.
Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with sustained decreases in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
30

The
Following the completion of the Callon acquisition the Company expectsrevised its full-year 20232024 estimated upstream capital investment will beto approximately $2$2.7 billion and remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.
The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs, if required.needs.
For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023.
37


Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented:
For the Three Months Ended
March 31,
20242023
For the Nine Months Ended
September 30,
20232022
(In millions)(In millions)
Sources of Cash and Cash Equivalents:Sources of Cash and Cash Equivalents:
Net cash provided by operating activitiesNet cash provided by operating activities$2,099 $3,530 
Net cash provided by operating activities
Net cash provided by operating activities
Proceeds from revolving credit facilities, netProceeds from revolving credit facilities, net202 — 
Proceeds from asset divestituresProceeds from asset divestitures29 778 
Proceeds from sale of Kinetik shares— 224 
Proceeds from sale of Kinetik Shares
Total Sources of Cash and Cash Equivalents
Total Sources of Cash and Cash Equivalents
Total Sources of Cash and Cash EquivalentsTotal Sources of Cash and Cash Equivalents2,330 4,532 
Uses of Cash and Cash Equivalents:Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas propertyAdditions to upstream oil and gas property$1,747 $1,168 
Acquisition of Delaware Basin properties24 563 
Additions to upstream oil and gas property
Additions to upstream oil and gas property
Leasehold and property acquisitionsLeasehold and property acquisitions11 30 
Payments on revolving credit facilities, net— 22 
Leasehold and property acquisitions
Leasehold and property acquisitions
Payments on commercial paper and revolving credit facilities, net
Payments on Apache fixed-rate debtPayments on Apache fixed-rate debt65 1,370 
Dividends paid to APA common stockholdersDividends paid to APA common stockholders232 127 
Distributions to noncontrolling interest – Egypt154 237 
Distributions to noncontrolling interest
Treasury stock activity, netTreasury stock activity, net208 884 
Deconsolidation of Altus cash and cash equivalents— 143 
Treasury stock activity, net
Treasury stock activity, net
Other, netOther, net39 22 
Total Uses of Cash and Cash EquivalentsTotal Uses of Cash and Cash Equivalents2,480 4,566 
Decrease in Cash and Cash Equivalents$(150)$(34)
Increase (Decrease) in Cash and Cash Equivalents
Sources of Cash and Cash Equivalents
Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.
Net cash provided by operating activities during the first ninethree months of 2024 totaled $368 million, up $33 million from the first three months of 2023, totaled $2.1 billion, down $1.4 billion from the first nine months of 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items.
For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
31

Proceeds from Revolving Credit Facilities, Net
As of September 30, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $768 million, an increase of $202 million since December 31, 2022.
Proceeds from Asset Divestitures The Company received $29$27 million and $778$21 million in proceeds from the divestiture of certain non-core assets during the first ninethree months of 2024 and 2023, and 2022, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first nine months of 2022. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
38


Proceeds from Sale of Kinetik Shares
The Company received $428 million of cash proceeds from the sale of its remaining shares of Kinetik Class A Common Stock in March 2024. 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.
Uses of Cash and Cash Equivalents
Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.7 billion$467 million and $1.2 billion$543 million during the first ninethree months of 20232024 and 2022,2023, respectively. The increasedecrease in capital investment is reflective of the increaseCompany’s strategy to continually assess drilling activity across its diverse portfolio and balance workover activity in the Company’s capital program that has gradually increased over the past year.Egypt. The Company operated an average of approximately 2423 drilling rigs during the first ninethree months of 2023,2024, compared to an average of approximately 2026 drilling rigs during the first ninethree months of 2022.
Acquisition of Delaware Basin Properties During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. Cash consideration paid during the first nine months of 2022 totaled $563 million.
Leasehold and Property Acquisitions During the first ninethree months of 20232024 and 2022,2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $11$63 million and $30$6 million, respectively.
Payments on and proceeds from commercial paper and revolving credit facilities, net During the first three months of 2024, the Company made net payments of $2 million on its commercial paper and revolving credit facilities borrowings. As of March 31, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $983 million, an increase of $417 million since December 31, 2022.
Payments on Apache Fixed-Rate Debt During the ninethree months ended September 30,March 31, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million.cash. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.
During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.
Dividends Paid to APA Common Stockholders The Company paid $232$76 million and $127$78 million during the first ninethree months of 20232024 and 2022,2023, respectively, for dividends on its common stock. During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.
Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $154$70 million and $237$17 million during the first ninethree months of 20232024 and 2022,2023, respectively, in cash distributions to Sinopec.
Treasury Stock Activity, net In the first ninethree months of 2023,2024, the Company repurchased 5.53.0 million shares at an average price of $37.91$33.27 per share totaling $208and an aggregate purchase price of approximately $101 million, and as of September 30, 2023,March 31, 2024, the Company had remaining authorization to repurchase 47.140.9 million shares. In the first ninethree months of 2022,2023, the Company repurchased 24.03.7 million shares at an average price of $36.78$38.93 per share totaling $884and an aggregate purchase price of approximately $142 million.
39


Liquidity
The following table presents a summary of the Company’s key financial indicators:
March 31,
2024
March 31,
2024
December 31,
2023
September 30,
2023
December 31,
2022
(In millions)(In millions)
Cash and cash equivalentsCash and cash equivalents$95 $245 
Total debt – APA and ApacheTotal debt – APA and Apache5,584 5,453 
Total equityTotal equity2,107 1,345 
Available committed borrowing capacity under syndicated credit facilitiesAvailable committed borrowing capacity under syndicated credit facilities2,164 2,238 
Cash and Cash Equivalents As of September 30, 2023,March 31, 2024, the Company had $95$102 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.
32


Debt As of September 30, 2023,March 31, 2024, the Company had $5.6$5.2 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility and commercial paper borrowings, and finance lease obligations. As of September 30, 2023,March 31, 2024, current debt included $2 million of finance lease obligations.
Committed 2022 Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).purposes.
One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each Newof the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than US$1.0 billion.
As of September 30, 2023,March 31, 2024, there were $768$30 million of borrowings under the USD Agreement and an aggregate £572£348 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023,March 31, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022,2023, there were $566$372 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement and an aggregate £652£348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement. The letters of creditdenominated in pounds were issued to support North Sea decommissioning obligations, the terms of which requiredrequire such support afterwhile Apache’s credit rating by Standard & Poor’s remains below BBB; on March 26, 2020, Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020., which was affirmed in 2023.
Uncommitted Credit Facilities Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2023March 31, 2024 and December 31, 2022,2023, there were no outstanding borrowings under these facilities. AsAt each of September 30,March 31, 2024 and December 31, 2023, there were £185£416 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17$2 million in letters of credit outstanding under these facilities.
Commercial Paper Program In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed $1.8 billion USD Agreement.
Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
As of March 31, 2024, there was $340 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
Term Loan Credit AgreementOn January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only on the date of closing of transactions under the Merger Agreement.Refer to “Subsequent Events” for further detail.Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.

40
33


Subsequent Events On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement. APA borrowed an aggregate $1.5 billion in senior unsecured term loans that mature April 1, 2027. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement.
The lenders under the Term Loan Credit Agreement committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA available for borrowing only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement, of which $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). APA elected to borrow only under the 3-Year Tranche Loans and to allow the lender commitments for the 364-Day Tranche Loans to expire.
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreemen)t, (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes). As of April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. Given the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and USD Agreement:
Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
On April 26, 2024, Callon notified holders of its election to fully redeem on May 6, 2024 the outstanding $8.3 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $15.6 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date.
Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023. There have been no material changes to the contractual obligations described therein.
34


Potential Decommissioning Obligations on Sold Properties
The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
In 2013, Apache sold its GOMGulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under(and subsequently emerged from) Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
protection. On August 3, 2020, Fieldwood again filed for protection under(and subsequently emerged from) Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Courtbankruptcy protection for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’sa second time. Upon emergence from this second bankruptcy, plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets willare to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
By letter dated April 5, 2022 replacing(replacing two prior letters dated September 8, 2021 and February 22, 2022,earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currentlywas obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
As of September 30,On June 21, 2023, two sureties that issued Bonds directly to Apache has incurred $692 million in decommissioning costs relatedand two sureties that issued bonds to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed fromthe issuing bank on the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimbursefiled suit against Apache for further decommissioning costs incurred with respectin a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to Legacy GOM Assets, thenprevent Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior liendrawing on the Legacy GOM Assets.
41


If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds and Letters of Credit and further alleged that they are exhausteddischarged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division) which subsequently held that the sureties’ state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is insufficientvoid. Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to repay any loans made bydraw down on the Bonds; however, the sureties refuse to pay such Bond draws. Apache underis vigorously pursuing its claims against the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.sureties.
As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly,March 31, 2024, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of September 30, 2023, the Company has also recorded a $411$186 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.
The Company has recorded contingent liabilities in the Trust A funds,amounts of $847 million and $824 million as of March 31, 2024 and December 31, 2023, respectively, representing the Bonds, and the Lettersestimated costs of Credit for decommissioning it may be required to perform on Legacylegacy GOM Assets. Ofproperties previously sold to Fieldwood and other GOM operators. During the total asset recorded, $38first quarter of 2024, the Company recognized $66 million is reflected under the caption “Decommissioning security forof “Loss on previously sold Gulf of Mexico properties,” and $373which includes increases of $33 million is reflected under “Other current assets.”related to orders received during the period from BSEE to decommission properties previously sold to Cox Operating LLC. The Company recognized no losses for decommissioning previously sold properties during the first quarter of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company’s financial position, results of operations, or liquidity.

35


Critical Accounting Estimates
The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023. 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, 2022.2023.
ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the recent conflict in Israel and Gaza, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.
42


The Company’s average crude oil price realizations decreased 12increased 3 percent from $97.81$78.37 per barrel to $86.15$80.65 per barrel during the thirdfirst quarters of 20222023 and 2023,2024, respectively. The Company’s average natural gas price realizations decreased 4423 percent from $5.62$3.22 per Mcf to $3.12$2.47 per Mcf during the thirdfirst quarters of 20222023 and 2023,2024, respectively. The Company’s average NGL price realizations decreased 33increased 5 percent from $33.39$24.84 per barrel to $22.26$26.20 per barrel during the thirdfirst quarters of 20222023 and 2023,2024, respectively. Based on average daily production for the thirdfirst quarter of 2023,2024, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $19$18 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8$7 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6$5 million.
The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2023,March 31, 2024, the Company had open natural gas derivatives not designated as cash flow hedges in an asseta liability position with a fair value of $16$2 million. A 10 percent increase in natural gas prices would decreaseincrease the assetliability by approximately $3$1 million, while a 10 percent decrease in prices would increasedecrease the assetliability by approximately $3$1 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2023.March 31, 2024. 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.
36


Interest Rate Risk
As of September 30, 2023,March 31, 2024, the Company had $4.8 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.34 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.
The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its commercial paper program and syndicated credit facilities. As of September 30, 2023,March 31, 2024, the Company had approximately $95$102 million in cash and cash equivalents, approximately 8469 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2023,March 31, 2024, there were $768$370 million of borrowings outstanding under the Company’s commercial paper program and syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments and credit facility borrowings are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.
Foreign Currency Exchange Rate Risk
The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss of $2$3 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2023.
43
March 31, 2024.


ITEM 4.    CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer, and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2023,March 31, 2024, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.
Changes in Internal Control Over Financial Reporting
There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended September 30, 2023March 31, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.
4437


PART II - OTHER INFORMATION
ITEM 1.    LEGAL PROCEEDINGS
Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 20222023 and Note 11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.
ITEM 1A.    RISK FACTORS
There have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023.
Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly ReportsReport on Form 10-Q for the quarterly periodsperiod ended March 31, 2023, June 30, 2023, and September 30, 20232024 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.2023.
ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information on shares of common stock repurchased by the Company during the quarter ended September 30, 2023:March 31, 2024:
Issuer Purchases of Equity SecuritiesIssuer Purchases of Equity SecuritiesIssuer Purchases of Equity Securities
PeriodPeriodTotal Number of Shares PurchasedAverage 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)
PeriodTotal Number of Shares PurchasedAverage Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2023— $— — 47,619,742
August 1 to August 31, 2023— — — 47,619,742
September 1 to September 30, 2023477,465 41.90 477,465 47,142,277
January 1 to January 31, 2024January 1 to January 31, 20242,226,352 $34.22 2,226,352 41,693,267
February 1 to February 29, 2024February 1 to February 29, 2024784,765 30.59 784,765 40,908,502
March 1 to March 31, 2024March 1 to March 31, 2024— — — 40,908,502
TotalTotal477,465$41.90 
(1) During the fourth quarter of 2021, the Company's Board of Directors authorized the purchase of 40 million shares of the Company's common stock. During September of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company is not obligated to acquire any specific number of shares.
ITEM 5.    OTHER INFORMATION
During the three months ended September 30, 2023,March 31, 2024, 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).
4538


ITEM 6.    EXHIBITS
Incorporated by ReferenceIncorporated by Reference
EXHIBIT
NO.
EXHIBIT
NO.
DESCRIPTIONFormExhibitFiling DateSEC File No.
2.12.18-K2.11/4/2024001-40144
3.13.13.18-K12B3.13/1/2021001-40144
3.23.23.28-K3.15/25/2023001-40144
3.33.33.38-K3.12/8/2023001-40144
*†10.1
4.14.18-K4.14/1/2024001-40144
10.110.18-K10.11/30/2024001-40144
10.210.28-K10.11/12/2024001-40144
*31.1*31.1
*31.2*31.2
*31.2
*31.2
**32.1
**32.1
**32.1**32.1
*101*101The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income, (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101
*101
*101.SCH
*101.SCH
*101.SCH*101.SCHInline XBRL Taxonomy Schema Document.
*101.CAL*101.CALInline XBRL Calculation Linkbase Document.
*101.CAL
*101.CAL
*101.DEF
*101.DEF
*101.DEF*101.DEFInline XBRL Definition Linkbase Document.
*101.LAB*101.LABInline XBRL Label Linkbase Document.
*101.LAB
*101.LAB
*101.PRE
*101.PRE
*101.PRE*101.PREInline XBRL Presentation Linkbase Document.
*104*104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*104
*104
*    Filed herewith
**    Furnished herewith
† Management contracts or compensatory plans or arrangements.

4639


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 APA CORPORATION
Dated:NovemberMay 2, 20232024 /s/ STEPHEN J. RINEY
 Stephen J. Riney
 Executive Vice President and Chief Financial Officer
 (Principal Financial Officer)
Dated:NovemberMay 2, 20232024 /s/ REBECCA A. HOYT
 Rebecca A. Hoyt
 Senior Vice President, Chief Accounting Officer, and Controller
 (Principal Accounting Officer)

4740