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apa-20220930

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, 2022


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to _________

Commission File Number: 1-40144

APA CORPORATION

(Exact name of registrant as specified in its charter)


Delaware			86-1430562
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.625 par value

APA

Nasdaq Global Select Market

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒


Number of shares of registrant’s common stock outstanding as of October 31, 2022			321,511,801

TABLE OF CONTENTS


Item		Page

	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)	2
	STATEMENT OF CONSOLIDATED CASH FLOWS	3
	CONSOLIDATED BALANCE SHEET	4
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
4.	CONTROLS AND PROCEDURES	47

	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	48
1A.	RISK FACTORS	48
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	49
6.	EXHIBITS	50

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, 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, 2021, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “goal,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:

•the scope, duration, and reoccurrence of any epidemics or pandemics (including, specifically, the coronavirus disease 2019 (COVID-19) pandemic and any related variants) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;

•the mandate, availability, and effectiveness of vaccine programs and therapeutics related to the treatment of COVID-19;

•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

•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 availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the impact of changes in tax legislation;

•the availability of goods and services;

•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;

•legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;

•the Company’s performance on environmental, social, and governance measures;

•terrorism or cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

•the Company’s ability to access the capital markets;

•market-related risks, such as general credit, liquidity, and interest-rate risks;

•the Company’s expectations with respect to the new operating structure implemented pursuant to the Holding Company Reorganization (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) and the associated disclosure implications;

•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, 2021;

•other risks and uncertainties disclosed in the Company’s third-quarter 2022 earnings release;

•other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q; and

•other factors disclosed in the other filings that the Company makes with the Securities and Exchange Commission.

Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.

DEFINITIONS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this Quarterly Report on Form 10-Q. As used herein:

“3-D” means three-dimensional.

“4-D” means four-dimensional.

“b/d” means barrels of oil or NGLs per day.

“bbl” or “bbls” means barrel or barrels of oil or NGLs.

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.

“boe/d” means boe per day.

“Btu” means a British thermal unit, a measure of heating value.

“Liquids” means oil and NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means the United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

With respect to information relating to the Company’s working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Company’s working interest therein. Unless otherwise specified, all references to wells and acres are gross.

References to “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	2,302	$	1,685	$	7,147	$	4,630
Purchased oil and gas sales	585		374		1,456		1,056
Total revenues	2,887		2,059		8,603		5,686
Derivative instrument gains (losses), net	(44)		—		(138)		45
Gain (loss) on divestitures, net	31		(2)		1,180		65
Loss on previously sold Gulf of Mexico properties	—		(446)		—		(446)
Other, net	(2)		40		107		175
	2,872		1,651		9,752		5,525
OPERATING EXPENSES:
Lease operating expenses	364		316		1,067		891
Gathering, processing, and transmission(1)	99		68		274		187
Purchased oil and gas costs	573		396		1,452		1,152
Taxes other than income	82		54		230		149
Exploration	95		34		193		109
General and administrative	69		70		314		239
Transaction, reorganization, and separation	4		4		21		8
Depreciation, depletion, and amortization	310		335		879		1,028
Asset retirement obligation accretion	29		29		87		85
Impairments	—		18		—		18
Financing costs, net	75		205		303		422
	1,700		1,529		4,820		4,288
NET INCOME BEFORE INCOME TAXES	1,172		122		4,932		1,237
Current income tax provision	357		183		1,164		463
Deferred income tax provision (benefit)	285		(31)		225		(54)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	530		(30)		3,543		828
Net income attributable to noncontrolling interest - Egypt	108		49		368		132
Net income attributable to noncontrolling interest - Altus	—		4		14		32
Net income (loss) attributable to Altus Preferred Unit limited partners	—		30		(70)		73
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	422	$	(113)	$	3,231	$	591

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	1.28	$	(0.30)	$	9.54	$	1.56
Diluted	$	1.28	$	(0.30)	$	9.51	$	1.53
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	329		379		339		378
Diluted	330		379		340		379

(1) For gathering, processing, and transmission costs associated with Kinetik, refer to Note 6—Equity Method Interest for further detail.

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	530	$	(30)	$	3,543	$	828
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Share of equity method interests other comprehensive income	—		—		—		1
Pension and postretirement benefit plan	—		—		(1)		—
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	530		(30)		3,542		829
Comprehensive income attributable to noncontrolling interest - Egypt	108		49		368		132
Comprehensive income attributable to noncontrolling interest - Altus	—		4		14		32
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners	—		30		(70)		73
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	422	$	(113)	$	3,230	$	592

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2022		2021

	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$	3,543	$	828
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument losses, net	119		18
Gain on divestitures, net	(1,180)		(65)
Exploratory dry hole expense and unproved leasehold impairments	129		67
Depreciation, depletion, and amortization	879		1,028
Asset retirement obligation accretion	87		85
Impairments	—		18
Provision (benefit) from deferred income taxes	225		(54)
Loss on extinguishment of debt	67		104
Loss on previously sold Gulf of Mexico properties	—		446
Other, net	(91)		(6)
Changes in operating assets and liabilities:
Receivables	(554)		(265)
Inventories	(81)		(19)
Drilling advances and other current assets	7		32
Deferred charges and other long-term assets	(3)		(46)
Accounts payable	175		219
Accrued expenses	249		29
Deferred credits and noncurrent liabilities	(41)		(8)
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,530		2,411
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(1,168)		(790)

Acquisition of Delaware Basin properties	(563)		—
Leasehold and property acquisitions	(30)		(6)

Proceeds from sale of oil and gas properties	778		239
Proceeds from sale of Kinetik shares	224		—
Deconsolidation of Altus cash and cash equivalents	(143)		—
Other, net	8		15
NET CASH USED IN INVESTING ACTIVITIES	(894)		(542)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) revolving credit facilities, net	(22)		290
Proceeds from Altus credit facility, net	—		33


Payments on Apache fixed-rate debt	(1,370)		(1,795)
Distributions to noncontrolling interest - Egypt	(237)		(203)
Distributions to Altus Preferred Unit limited partners	(11)		(34)
Treasury stock activity, net	(884)		—
Dividends paid to APA common stockholders	(127)		(28)
Other, net	(19)		(17)
NET CASH USED IN FINANCING ACTIVITIES	(2,670)		(1,754)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(34)		115
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	302		262
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	268	$	377

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	274	$	365
Income taxes paid, net of refunds	1,029		415

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

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	September 30, 2022(1)		December 31, 2021(1)

	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($132 related to Altus VIE)	$	268	$	302
Receivables, net of allowance of $115 and $109	1,928		1,394
Other current assets (Note 5) ($9 related to Altus VIE)	939		684
	3,135		2,380
PROPERTY AND EQUIPMENT:
Oil and gas properties	41,998		40,749
Gathering, processing, and transmission facilities ($209 related to Altus VIE)	447		673
Other ($3 related to Altus VIE)	606		1,126
Less: Accumulated depreciation, depletion, and amortization ($25 related to Altus VIE)	(34,055)		(34,213)
	8,996		8,335
OTHER ASSETS:
Equity method interests (Note 6) ($1,365 related to Altus VIE)	602		1,365
Decommissioning security for sold Gulf of Mexico properties (Note 11)	376		640
Deferred charges and other ($6 related to Altus VIE)	520		583
	$	13,629	$	13,303

LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable ($12 related to Altus VIE)	$	954	$	731
Current debt	125		215
Other current liabilities (Note 7) ($15 related to Altus VIE)	1,905		1,171
	2,984		2,117
LONG-TERM DEBT (Note 9) ($657 related to Altus VIE)	5,404		7,295
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	384		148
Asset retirement obligation (Note 8) ($68 related to Altus VIE)	2,078		2,089
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	801		1,086
Other ($67 related to Altus VIE)	427		573
	3,690		3,896
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	—		712
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 419,757,104 and 419,078,606 shares issued, respectively	262		262
Paid-in capital	11,494		11,645
Accumulated deficit	(6,257)		(9,488)
Treasury stock, at cost, 96,185,289 and 72,147,841 shares, respectively	(4,920)		(4,036)
Accumulated other comprehensive income	21		22
APA SHAREHOLDERS’ EQUITY (DEFICIT)	600		(1,595)
Noncontrolling interest - Egypt	951		820
Noncontrolling interest - Altus	—		58
TOTAL EQUITY (DEFICIT)	1,551		(717)
	$	13,629	$	13,303

(1) The Altus VIE amounts are disclosed as of December 31, 2021. All Altus balances were deconsolidated as of February 22, 2022. Refer to Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures for further detail.

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS

(Unaudited)


	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)

	(In millions)
For the Quarter Ended September 30, 2021
Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76
Net loss attributable to common stock	—		—		—		(113)		—		—		(113)		—		(113)
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		49		49
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		4		4
Net income attributable to Altus Preferred Unit limited partners	30		—		—		—		—		—		—		—		—

Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(143)		(143)
Common dividends declared ($0.0625 per share)	—		—		(24)		—		—		—		(24)		—		(24)
Other	—		—		6		—		—		—		6		(5)		1
Balance at September 30, 2021	$	635	$	262	$	11,686	$	(9,870)	$	(3,188)	$	15	$	(1,095)	$	945	$	(150)

For the Quarter Ended September 30, 2022
Balance at June 30, 2022	$	—	$	262	$	11,567	$	(6,679)	$	(4,587)	$	21	$	584	$	921	$	1,505
Net income attributable to common stock	—		—		—		422		—		—		422		—		422
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		108		108




Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(78)		(78)
Common dividends declared ($0.25 per share)	—		—		(80)		—		—		—		(80)		—		(80)
Treasury stock activity, net	—		—		—		—		(333)		—		(333)		—		(333)

Other	—		—		7		—		—		—		7		—		7
Balance at September 30, 2022	$	—	$	262	$	11,494	$	(6,257)	$	(4,920)	$	21	$	600	$	951	$	1,551

(1) As a result of the BCP Business Combination, the Company deconsolidated Altus 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.

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS - Continued

(Unaudited)


	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Nine Months Ended September 30, 2021
Balance at December 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)
Net income attributable to common stock	—		—		—		591		—		—		591		—		591
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		132		132
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		32		32
Net income attributable to Altus Preferred Unit limited partners	73		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	(34)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(203)		(203)
Common dividends declared ($0.1125 per share)	—		—		(43)		—		—		—		(43)		—		(43)
Other	—		—		(6)		—		1		1		(4)		(10)		(14)
Balance at September 30, 2021	$	635	$	262	$	11,686	$	(9,870)	$	(3,188)	$	15	$	(1,095)	$	945	$	(150)

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

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

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, 2021, which contains a summary of the Company’s significant accounting policies and other disclosures.

On March 1, 2021, Apache Corporation, the Company’s predecessor registrant, consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2022, 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, 2021. The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation, if applicable.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.

The implementation of the Holding Company Reorganization was accounted for as a merger under common control. APA recognized the assets and liabilities of Apache at carryover basis. The consolidated financial statements of APA present comparative information for prior years on a combined basis, as if both APA and Apache were under common control for all periods presented.

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements.

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors 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 variable interest entity 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. Additionally, the assets of ALTM could only be used to settle obligations of ALTM. There was no recourse to the Company for ALTM’s liabilities.

On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of ALTM. The Company further determined that ALTM no longer qualified as a variable interest entity under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 2—Acquisitions and Divestitures for further detail.

The stockholders agreement entered into by and among the Company, ALTM, BCP, and other related and affiliated entities provides that the Company, through one of its wholly owned subsidiaries, retains the ability to designate a director to the board of directors of Kinetik for so long as the Company and its affiliates beneficially own 10 percent or more of Kinetik’s outstanding common stock. Based on this board representation, combined with the Company’s stock ownership, management determined it has significant influence over Kinetik. Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 6—Equity Method Interests for further detail.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimate of income taxes (refer to Note 10—Income Taxes), the estimation of the contingent liability representing Apache’s potential obligation to decommission 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, Note 9—Debt and Financing Costs, and Note 12—Redeemable Noncontrolling Interest — Altus for further detail regarding the Company’s fair value measurements recorded on a recurring basis.

During the three and nine months ended September 30, 2022, the Company recorded no asset impairments in connection with fair value assessments. During the three and nine months ended September 30, 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2022 and 2021.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.8 billion and $1.3 billion as of September 30, 2022 and December 31, 2021, respectively.

Oil and gas production revenues from non-customers represent income taxes paid to the Arab Republic of Egypt by Egyptian General Petroleum Corporation on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil, natural gas, and natural gas liquids production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.

Refer to Note 14—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.

In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.

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, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.

Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission (GPT) Facilities

GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.

2. ACQUISITIONS AND DIVESTITURES

2022 Activity

On July 29, 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for approximately $593 million, subject to further post-closing adjustments. Final cash settlement is anticipated to be completed during the fourth quarter of 2022. The Company recorded $567 million for proved properties, $30 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 quarter of 2022, the Company completed a previously announced transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million.

The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of Common Stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM Common Stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM Common Stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of ALTM 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 of the Company’s share of ALTM’s deconsolidated balance sheet and the fair value of its approximate 20 percent retained ownership in the combined entity. A summary of components of the gain, including the ALTM balance sheet amounts deconsolidated at the time of close, is included below:


	As of February 22, 2022
	(In millions)

Fair value of Kinetik Class A Common Stock held by Company	$	802

ASSETS:
Cash and cash equivalents	$	143
Other current assets	29
Property and equipment, net	184
Equity method interests	1,367
Other noncurrent assets	12
Total assets deconsolidated	$	1,735

LIABILITIES:
Current liabilities	$	3
Long-term debt	657
Other noncurrent liabilities	168
Total liabilities deconsolidated	$	828

NONCONTROLLING INTERESTS:
Redeemable noncontrolling interest preferred unit limited partners	$	642
Noncontrolling interest-Altus	72
Total noncontrolling interests deconsolidated	$	714

Net effect of deconsolidating balance sheet	$	(193)

Gain on deconsolidation of ALTM	$	609

During the first quarter of 2022, the Company sold four million of its shares in Kinetik 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. In connection with this secondary offering, the Company agreed that, within 24 months of closing the offering, it will invest a minimum of $100 million of the proceeds of the offering for new well drilling and completion activity at the Alpine High play in the Delaware Basin, where Kinetik has exclusive gas and NGL gathering and processing rights.

2021 Activity

During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million, for cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $63 million in connection with the sale.

During the first nine months of 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $65 million. The Company recognized a gain of approximately $2 million upon closing of these transactions.

During the first nine months of 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $6 million.

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $519 million and $321 million as of September 30, 2022 and December 31, 2021, respectively. The increase is attributable to additional drilling activity in Suriname, North Sea, and Egypt. No suspended exploratory well costs previously capitalized for greater than one year at December 31, 2021 were charged to dry hole expense during the nine months ended September 30, 2022.

Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

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

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2022, the Company had derivative positions with 12 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, 2022, the Company had the following open natural gas financial basis swap contracts:


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2022	NYMEX Henry Hub/IF Waha	22,080	$(0.71)	—	—
October—December 2022	NYMEX Henry Hub/IF HSC	—	—	22,080	$(0.12)
January—March 2023	NYMEX Henry Hub/IF Waha	3,150	$(1.06)	—	—
January—March 2023	NYMEX Henry Hub/IF HSC	—	—	3,150	$(0.03)
January—June 2023	NYMEX Henry Hub/IF Waha	4,525	$(1.54)	—	—
January—June 2023	NYMEX Henry Hub/IF HSC	—	—	4,525	$(0.11)
July—September 2023	NYMEX Henry Hub/IF Waha	1,840	$(1.62)	—	—
July—September 2023	NYMEX Henry Hub/IF HSC	—	—	1,840	$(0.19)
January—December 2023	NYMEX Henry Hub/IF Waha	73,000	$(1.15)	—	—
January—December 2023	NYMEX Henry Hub/IF HSC	—	—	73,000	$(0.08)
January—June 2024	NYMEX Henry Hub/IF Waha	16,380	$(1.15)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	16,380	$(0.10)

Foreign Currency Derivative Instruments

The Company has open foreign currency costless collar contracts in GBP/USD for £15 million per month for the calendar year 2022 with a weighted average floor and ceiling price of $1.29 and $1.39, respectively.

Embedded Derivatives

Altus Preferred Units Embedded Derivative

The Altus Preferred Units embedded derivative was deconsolidated as of March 31, 2022 as part of the BCP Business Combination. Refer to Note 2 —Acquisitions and Divestitures for discussion of the BCP Business Combination and Note 12—Redeemable Noncontrolling Interest — Altus for a description of the Altus Preferred Units and associated embedded derivative.

Pipeline Capacity Embedded Derivatives

During the fourth quarter of 2019 and first quarter of 2020, the Company entered into agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements were arrangements under which the Company received payments calculated based on pricing differentials between Houston Ship Channel and Waha during the calendar years 2020 and 2021. This feature required bifurcation and measurement of the change in market value throughout 2020 and 2021. Unrealized gains and losses in the fair value of this feature were recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations, and the balance at the end of December 31, 2021 will be amortized into income over the original tenure of the host contract.

Fair Value Measurements

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
September 30, 2022
Assets:
Commodity derivative instruments	$	—	$	—	$	—	$	—	$	3	$	3
Liabilities:
Commodity derivative instruments	—		88		—		88		3		91
Foreign currency derivative instruments	—		8		—		8		—		8



December 31, 2021


Liabilities:
Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Pipeline capacity embedded derivative	—		46		—		46		—		46
Preferred Units embedded derivative	—		—		57		57		—		57

(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties and reclassifications between long-term and short-term balances.

The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.

Derivative Activity Recorded in the Consolidated Balance Sheet

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	September 30, 2022		December 31, 2021

	(In millions)
Current Assets: Other current assets	$	—	$	—
Other Assets: Deferred charges and other	3		—
Total derivative assets	$	3	$	—

Current Liabilities: Other current liabilities	$	96	$	4
Deferred Credits and Other Noncurrent Liabilities: Other	3		109
Total derivative liabilities	$	99	$	113

Derivative Activity Recorded in the Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Realized:
Commodity derivative instruments	$	(2)	$	(37)	$	(11)	$	63
Foreign currency derivative instruments	(6)		—		(8)		—
Realized gain (loss), net	(8)		(37)		(19)		63
Unrealized:
Commodity derivative instruments	(35)		29		(79)		(43)
Pipeline capacity embedded derivatives	—		3		—		6
Foreign currency derivative instruments	(1)		—		(9)		—
Preferred Units embedded derivative	—		5		(31)		19
Unrealized gain (loss), net	(36)		37		(119)		(18)
Derivative instrument gains (losses), net	$	(44)	$	—	$	(138)	$	45

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 losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

The Company seeks to maintain a balance between “first of month” and “gas daily pricing” for its U.S. natural gas portfolio and sales activities in a given month as part of its ordinary course of business. This is typically implemented through a combination of physical and financial contracts that settle monthly. In January 2021, the Company entered into financial contracts that increased its exposure to “gas daily pricing” and reduced its exposure to “first of month” pricing for February 2021. The Company realized a gain of $147 million in connection with these contracts in the first quarter of 2021 as a result of extreme daily gas price volatility across Texas in February resulting from Winter Storm Uri.

5. OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets:


	September 30, 2022		December 31, 2021

	(In millions)
Inventories	$	491	$	473
Drilling advances	75		55

Prepaid assets and other	23		56
Current decommissioning security for sold Gulf of Mexico assets	350		100
Total Other current assets	$	939	$	684

6. EQUITY METHOD INTERESTS

The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments and dividends received are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.

The initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain (loss) on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2–Acquisitions and Divestitures for further detail.

During the second quarter of 2022, Kinetik issued a two-for-one split of its Common Stock.

During the third quarter and first nine months of 2022, the Company received approximately 0.4 million shares and 0.7 million shares, respectively, of Kinetik’s Class A Common Stock as paid-in-kind dividends. Also during the third quarter and first nine months of 2022, the Company recorded fair value adjustments on its ownership in Kinetik totaling a loss of $30 million and a gain of $23 million, respectively. The Company’s ownership of 18.5 million shares represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock as of September 30, 2022.

The following table presents the activity in the Company’s equity method interest in Kinetik for the nine months ended September 30, 2022:


		Kinetik Holdings Inc

	(In millions)
Balance at December 31, 2021		$	—
Initial interest upon closing the BCP Business Combination		802
Sale of Class A shares		(250)
Paid-in-kind dividend		27
Fair value adjustments		23
Balance at September 30, 2022		$	602

During the three and nine months ended September 30, 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the transaction totaling $28 million and $64 million, respectively. As of September 30, 2022, the Company has recorded accrued GPT costs payable to Kinetik of approximately $18 million.

Prior to the deconsolidation of Altus on February 22, 2022, the Company, through its ownership of Altus, had the following equity method interests in four Permian Basin long-haul pipeline entities, which were accounted for under the equity method of accounting at December 31, 2021. For each of the equity method interests, Altus had the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentages held by the Company and associated carrying values for each entity:


	Interest	December 31, 2021

		(In millions)
Gulf Coast Express Pipeline, LLC	16.0%	$	274
EPIC Crude Holdings, LP	15.0%	—
Permian Highway Pipeline, LLC	26.7%	630
Shin Oak Pipeline (Breviloba, LLC)	33.0%	461
Total Altus equity method interests		$	1,365

The following table presents the activity in Altus’ equity method interests for the nine months ended September 30, 2022:


	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total

	(In millions)






Balance at December 31, 2021	$	274	$	—	$	630	$	461	$	1,365
Capital contributions	—		2		—		—		2
Distributions	(5)		—		(9)		(7)		(21)

Equity income (loss), net	8		(2)		10		5		21

Deconsolidation of Altus	(277)		—		(631)		(459)		(1,367)
Balance at September 30, 2022	$	—	$	—	$	—	$	—	$	—

For discussion of the financial statement impacts related to the deconsolidation of ALTM, refer to N ote 2—Acquisitions and Divestitures.

7. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities:


	September 30, 2022		December 31, 2021

	(In millions)
Accrued operating expenses	$	157	$	129
Accrued exploration and development	368		207
Accrued compensation and benefits	308		292
Accrued interest	69		107
Accrued income taxes	145		28
Current asset retirement obligation	40		41
Current operating lease liability	114		99
Current portion of derivatives at fair value	96		4
Current decommissioning contingency for sold Gulf of Mexico properties	350		100
Other	258		164
Total Other current liabilities	$	1,905	$	1,171

8. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability:


	September 30, 2022
	(In millions)
Asset retirement obligation, December 31, 2021	$	2,130
Liabilities incurred	4
Liabilities acquired	4
Liabilities settled	(34)
Liabilities divested	(4)

Deconsolidation of Altus	(69)
Accretion expense	87

Asset retirement obligation, September 30, 2022	2,118
Less current portion	(40)
Asset retirement obligation, long-term	$	2,078

9. DEBT AND FINANCING COSTS

The following table presents the carrying values of the Company’s debt:


	September 30, 2022		December 31, 2021

	(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	5,032	$	6,344
Altus credit facility(2)	—		657
Syndicated credit facilities(2)	520		542
Apache finance lease obligations	34		36
Unamortized discount	(28)		(30)
Debt issuance costs	(29)		(39)
Total debt	5,529		7,510
Current maturities	(125)		(215)
Long-term debt	$	5,404	$	7,295

(1) The fair values of the Apache notes and debentures were $4.3 billion and $7.1 billion as of September 30, 2022 and December 31, 2021, respectively.

The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.

As of September 30, 2022, current debt included $123 million carrying value of Apache’s 2.625% senior notes due January 15, 2023 and $2 million of finance lease obligations. As of December 31, 2021, current debt included $213 million carrying value of Apache’s 3.25% senior notes due April 15, 2022 and $2 million of finance lease obligations.

During the quarter ended September 30, 2022, Apache notified holders of its 2.625% notes due 2023 that Apache elected to redeem the notes on October 17, 2022, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption, including the $123 million outstanding principal amount of the notes, was financed in part by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

During the quarter ended March 31, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases.

During the quarter ended March 31, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases.

During the quarter ended March 31, 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% of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

On April 29, 2022, the Company entered into two syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 syndicated credit agreement (the Former Facility).

•One new 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 new agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2022, there were $520 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £748 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2021, there were $542 million of borrowings and an aggregate £748 million and $20 million in letters of credit outstanding under the Former Facility. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

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, 2022 and December 31, 2021, there were no outstanding borrowings under these facilities. As of September 30, 2022 and December 31, 2021, there were £117 million and $17 million in letters of credit outstanding under these facilities.

Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Interest expense	$	80	$	102	$	249	$	324
Amortization of debt issuance costs	1		1		8		6
Capitalized interest	(5)		(2)		(13)		(6)
Loss on extinguishment of debt	—		105		67		104
Interest income	(1)		(1)		(8)		(6)
Financing costs, net	$	75	$	205	$	303	$	422

10. INCOME TAXES

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

During the third quarter of 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 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2021, the Company’s effective income tax rate was primarily impacted by a loss contingency in connection with decommissioning of previously sold Gulf of Mexico properties and an increase 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. The Company’s 2021 year-to-date effective income tax rate was primarily impacted by a loss on offshore decommissioning contingency and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.

On May 26, 2022, the U.K. Chancellor announced a new tax on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. On June 21, 2022, the U.K. Government published draft legislation concerning this new tax and on July 14, 2022, the Energy (Oil and Gas) Profits Levy Act 2022 was enacted, receiving Royal Assent. Under the new law, an additional levy is assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the third quarter of 2022, the Company has recorded a deferred tax expense of $230 million related to the remeasurement of the June 30, 2022 U.K. deferred tax liability.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company.

The Company is subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

11. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2022, the Company has an accrued liability of approximately $30 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

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, 2021.

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, 2021, Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2022, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiff’s claims. Further appeal is pending.

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

Canadian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. The Company believes that Plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, 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 and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases were sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state court. The 9th Circuit has since, once again, affirmed the district court’s remand to state court. The defendants are appealing this latest remand decision to the U.S. Supreme Court. Further activity in the cases has been stayed pending further appellate review.

On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. After removal of this lawsuit to federal court, the district court remanded it back to state court. The 3rd Circuit has since, once again, affirmed the district court’s remand to state court. The defendants are appealing this latest remand decision to the U.S. Supreme Court.

The Company believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company. Further appeal is pending.

Oklahoma Class Action

The Company is a party to a purported class action in Oklahoma styled Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219.

The Allen case seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. With no admission of liability or wrongdoing, but only to avoid the expense and uncertainty of future litigation, Apache has entered into a settlement agreement in the Allen case to resolve all claims made against it by the class. The settlement agreement is subject to court approval and a full fairness hearing will 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.

Shareholder and Derivative Lawsuits

On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, (1) alleges that the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) alleges that the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) alleges that these statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) alleges that, as a result, the Company’s public statements were materially false and misleading. The Company believes that plaintiffs’ claims lack merit and intends to vigorously defend this lawsuit.

On March 16, 2021, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 334th District Court of Harris County, Texas. The case purports to be a derivative action brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. On March 17, 2022, the trial court granted Defendants’ Special Exceptions and dismissed the claim with prejudice.

Environmental Matters

As of September 30, 2022, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

The Company is not aware of any environmental claims existing as of September 30, 2022 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, respectively, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache expects to obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.

As of September 30, 2022, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $1.2 billion as of September 30, 2022, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $801 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $350 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company has also recorded a $726 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $376 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $350 million is reflected under “Other current assets.” 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. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.

12. REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers.

Classification

Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Pursuant to this method, the net transaction price was accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment was limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end was equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price.

Activity related to the Preferred Units is as follows:


	Units Outstanding	Financial Position

	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units at: December 31, 2020	660,694	$	608
Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment	N/A	82
Redeemable noncontrolling interest — Preferred Units at: December 31, 2021	660,694	712

Allocation of Altus Midstream LP net income	N/A	12
Accreted value adjustment(1)	N/A	(82)
Redeemable noncontrolling interest — Preferred Units at: February 22, 2022	660,694	642
Preferred Units embedded derivative		89
Deconsolidation of Altus		(731)
		$	—

(1) Includes the reversal of previously recorded accreted value adjustments of $53 million due to the deconsolidation of Altus.

N/A - not applicable.

13. CAPITAL STOCK

Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization.

Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan.

Net Income (Loss) per Common Share

The following table presents a reconciliation of the components of basic and diluted net income per common share in the consolidated financial statements:


	For the Quarter Ended September 30,
	2022					2021
	Income		Shares	Per Share		Loss		Shares	Per Share

	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	422	329	$	1.28	$	(113)	379	$	(0.30)
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	—	$	—

Diluted:
Income (loss) attributable to common stock	$	422	330	$	1.28	$	(113)	379	$	(0.30)

	For the Nine Months Ended September 30,
	2022					2021
	Income		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	3,231	339	$	9.54	$	591	378	$	1.56
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	(0.03)	$	—	1	$	—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	—		—	—		(10)		—	(0.03)
Diluted:
Income attributable to common stock	$	3,231	340	$	9.51	$	581	379	$	1.53

Prior to the deconsolidation of Altus on February 22, 2022, the Company used the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream LP for shares of Altus Midstream Company’s common stock. The impact to net income and loss attributable to common stock on an assumed conversion of the Preferred Units was anti-dilutive for the quarter ended September 30, 2021. The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 2.1 million and 3.2 million during the third quarters of 2022 and 2021, respectively, and 2.5 million and 3.4 million during the first nine months of 2022 and 2021, respectively.

Stock Repurchase Program

During 2018, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. No shares were purchased under this authorization through December 31, 2020. 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. Shares may be purchased either in the open market or through privately negotiated transactions.

In the third quarter of 2022, the Company repurchased 9.8 million shares at an average price of $33.86 per share, and as of September 30, 2022, the Company had remaining authorization to repurchase up to 64.8 million shares. For the nine months ended September 30, 2022, the Company repurchased 24.0 million shares at an average price of $36.78 per share. The Company is not obligated to acquire any additional shares. The Company did not repurchase any shares during the nine months ended September 30, 2021.

The Company repurchased 2.1 million shares at an average price of $40.40 per share in October 2022, and as of October 31, 2022, the Company had remaining authorization to repurchase up to 62.7 million shares.

The Company is not obligated to acquire any additional shares.

Common Stock Dividends

For the quarters ended September 30, 2022 and 2021, the Company paid $41 million and $9 million, respectively, in dividends on its common stock. For the nine months ended September 30, 2022 and 2021, the Company paid $127 million and $28 million, respectively, in dividends on its common stock.

During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021, approved a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend to $0.25 per share.

14. BUSINESS SEGMENT INFORMATION

As of September 30, 2022, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces 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 Altus Midstream Company, 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 other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Quarter Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	739	$	303	$	630	$	—	$	—	$	1,672
Natural gas revenues	84		44		300		—		—		428
Natural gas liquids revenues	—		5		197		—		—		202
Oil, natural gas, and natural gas liquids production revenues	823		352		1,127		—		—		2,302
Purchased oil and gas sales	—		—		585		—		—		585

	823		352		1,712		—		—		2,887
Operating Expenses:
Lease operating expenses	119		107		138		—		—		364
Gathering, processing, and transmission	5		7		87		—		—		99
Purchased oil and gas costs	—		—		573		—		—		573
Taxes other than income	—		—		82		—		—		82
Exploration	29		1		16		—		49		95
Depreciation, depletion, and amortization	97		52		161		—		—		310
Asset retirement obligation accretion	—		21		8		—		—		29

	250		188		1,065		—		49		1,552
Operating Income (Loss)(2)	$	573	$	164	$	647	$	—	$	(49)	1,335

Other Income (Expense):
Derivative instrument losses, net											(44)

Gain on divestitures, net											31
Other, net											(2)
General and administrative											(69)
Transaction, reorganization, and separation											(4)
Financing costs, net											(75)
Income Before Income Taxes											$	1,172


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2022	(In millions)
Revenues:
Oil revenues	$	2,431	$	938	$	1,883	$	—	$	—	$	5,252
Natural gas revenues	270		207		764		—		—		1,241
Natural gas liquids revenues	6		33		618		—		(3)		654
Oil, natural gas, and natural gas liquids production revenues	2,707		1,178		3,265		—		(3)		7,147
Purchased oil and gas sales	—		—		1,451		5		—		1,456
Midstream service affiliate revenues	—		—		—		16		(16)		—
	2,707		1,178		4,716		21		(19)		8,603
Operating Expenses:
Lease operating expenses	381		321		366		—		(1)		1,067
Gathering, processing, and transmission	15		31		241		5		(18)		274
Purchased oil and gas costs	—		—		1,452		—		—		1,452
Taxes other than income	—		—		227		3		—		230
Exploration	56		8		21		—		108		193
Depreciation, depletion, and amortization	285		168		424		2		—		879
Asset retirement obligation accretion	—		61		25		1		—		87

	737		589		2,756		11		89		4,182
Operating Income (Loss)(2)	$	1,970	$	589	$	1,960	$	10	$	(108)	4,421

Other Income (Expense):
Derivative instrument losses, net											(138)

Gain on divestitures, net											1,180
Other, net											107
General and administrative											(314)
Transaction, reorganization, and separation											(21)
Financing costs, net											(303)
Income Before Income Taxes											$	4,932

Total Assets(3)	$	3,242	$	2,185	$	7,675	$	—	$	527	$	13,629


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Quarter Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	465	$	233	$	484	$	—	$	—	$	1,182
Natural gas revenues	63		42		188		—		—		293
Natural gas liquids revenues	2		6		202		—		—		210
Oil, natural gas, and natural gas liquids production revenues	530		281		874		—		—		1,685
Purchased oil and gas sales	—		—		374		—		—		374
Midstream service affiliate revenues	—		—		—		35		(35)		—
	530		281		1,248		35		(35)		2,059
Operating Expenses:
Lease operating expenses	117		101		98		—		—		316
Gathering, processing, and transmission	4		8		82		9		(35)		68
Purchased oil and gas costs	—		—		396		—		—		396
Taxes other than income	—		—		52		2		—		54
Exploration	14		4		3		—		13		34
Depreciation, depletion, and amortization	128		61		143		3		—		335
Asset retirement obligation accretion	—		20		8		1		—		29
Impairments	—		18		—		—		—		18
	263		212		782		15		(22)		1,250
Operating Income (Loss)(2)	$	267	$	69	$	466	$	20	$	(13)	809

Other Income (Expense):
Loss on offshore decommissioning contingency											(446)

Loss on divestitures, net											(2)
Other, net											40
General and administrative											(70)
Transaction, reorganization, and separation											(4)
Financing costs, net											(205)
Income Before Income Taxes											$	122


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(4)
	Upstream

For the Nine Months Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	1,299	$	690	$	1,325	$	—	$	—	$	3,314
Natural gas revenues	198		100		533		—		—		831
Natural gas liquids revenues	6		16		463		—		—		485
Oil, natural gas, and natural gas liquids production revenues	1,503		806		2,321		—		—		4,630
Purchased oil and gas sales	—		—		1,050		6		—		1,056
Midstream service affiliate revenues	—		—		—		99		(99)		—
	1,503		806		3,371		105		(99)		5,686
Operating Expenses:
Lease operating expenses	335		274		283		—		(1)		891
Gathering, processing, and transmission	8		28		225		24		(98)		187
Purchased oil and gas costs	—		—		1,147		5		—		1,152
Taxes other than income	—		—		139		10		—		149
Exploration	36		27		21		—		25		109
Depreciation, depletion, and amortization	395		208		416		9		—		1,028
Asset retirement obligation accretion	—		59		23		3		—		85
Impairments	—		18		—		—		—		18
	774		614		2,254		51		(74)		3,619
Operating Income (Loss)(2)	$	729	$	192	$	1,117	$	54	$	(25)	2,067

Other Income (Expense):
Derivative instrument gains, net											45
Loss on offshore decommissioning contingency											(446)
Gain on divestitures, net											65
Other, net											175
General and administrative											(239)
Transaction, reorganization, and separation											(8)
Financing costs, net											(422)
Income Before Income Taxes											$	1,237

Total Assets(3)	$	2,887	$	2,080	$	6,197	$	1,853	$	293	$	13,310

(1)Includes revenue from non-customers for the quarters and nine months ended September 30, 2022 and 2021 of:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Oil	$	227	$	112	$	779	$	302
Natural gas	26		11		87		33
Natural gas liquids	—		1		2		1

(2)Operating income of U.S. and Egypt includes leasehold impairments of $15 million and $1 million, respectively, for the third quarter of 2022.
Operating income of U.S. and Egypt includes leasehold impairments of $19 million and $3 million, respectively, for the first nine months of 2022.
Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $2 million, $2 million, and $19 million, respectively, for the third quarter of 2021.
Operating income of U.S., Egypt, and North Sea includes leasehold impairments and other asset impairments of $19 million, $6 million, and $19 million, respectively, for the first nine months of 2021.

(3)Intercompany balances are excluded from total assets.

(4)Includes noncontrolling interests in Egypt and Altus prior to deconsolidation.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

On March 1, 2021, Apache Corporation consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.

Overview

APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas.

Today, the world faces a dual challenge: To meet growing demand for energy and to do so in a cleaner, more sustainable way. APA believes society can accomplish both and strives to meet those challenges while creating value for all its stakeholders. The global economy and the energy industry have been deeply impacted by the effects of the conflict in Ukraine and coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainties in the global supply chain, commodity prices, and financial markets, including the impact of inflation and rising interest rates, continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its stakeholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

In the third quarter of 2022, the Company reported net income attributable to common stock of $422 million, or $1.28 per diluted share, compared to a net loss of $113 million, or $0.30 per diluted share, in the third quarter of 2021. Net income for the third quarter of 2022 benefited from higher revenues attributable to a new merged concession agreement in Egypt and higher commodity prices. The increase in realized prices was primarily driven by the effects of global inflation, the conflict in Ukraine on global commodity prices, and uncertainties around spare capacity and energy security globally.

The Company generated $3.5 billion of cash from operating activities during the first nine months of 2022, a 46 percent increase from the first nine months of 2021, driven by higher oil and gas revenues. Since year-end 2021, the Company has reduced its total outstanding debt and redeemable preferred interests by $2.0 billion and $712 million, respectively, through the deconsolidation of ALTM and the retirement of outstanding notes and debentures. The Company also repurchased 24.0 million shares of its common stock for $884 million during the first nine months of 2022. The Company had $268 million of cash on hand at September 30, 2022.

The Company remains committed to its capital return framework established in the prior year 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 fourth quarter of 2021 from $0.0625 per share to $0.125 per share. The dividend was further increased in the third quarter of 2022 to $0.25 per share, representing a return to pre-COVID-19 dividend levels.

•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2022, the Company has repurchased 55.2 million shares of the Company’s common stock. As of September 30, 2022, the Company had remaining authorization to repurchase up to 64.8 million shares under the Company’s share repurchase programs.

The Company does not anticipate any significant changes to the activity levels set forth earlier this year in its three-year capital investment program or capital return framework in the context of higher strip oil and gas prices, remaining committed to safe, steady, and efficient operations across all assets and returning free cash flow to shareholders through dividends and share repurchases.

Operational Highlights

Key operational highlights for the quarter include:

United States

•During the quarter, the Company closed a transaction to acquire properties in the Texas Delaware Basin near existing operations, primarily in Loving and Reeves counties, with net proved reserves of approximately 37 MMboe. The acquired properties have a combination of producing wells, wells in the process of drilling and completion, and an inventory of undrilled locations. The transaction closed on July 29, 2022 for approximately $593 million, subject to further post-closing adjustments. Final cash settlement is anticipated to be completed during the fourth quarter of 2022.

•Daily boe production from the Company’s U.S. assets accounted for 57 percent of its total production during the third quarter of 2022. The Company’s core Midland Basin development program and newly acquired properties in the Texas Delaware Basin are expected to represent key growth areas for the U.S. assets.

International

•In Egypt, the Company averaged 15 drilling rigs and drilled 25 new productive wells during the third quarter of 2022. Third quarter 2022 gross equivalent production in the Company’s Egypt assets decreased 5 percent from the third quarter of 2021, while net production increased 21 percent, primarily a function of improved cost recovery under the new merged concession agreement ratified at the end of 2021. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. The Company continues to increase drilling and workover activity as a result of the merged concession agreement. Egypt production growth is anticipated in the fourth quarter on improvements in new well connections and recompletion activity.

•On the environmental, social and governance (ESG) front, the Company has delivered on its upstream flaring reduction goal in Egypt, flaring at least 40 percent less gas than would otherwise be flared without these initiatives, instead now compressing this gas into sales lines.

•The Company averaged two rigs in the North Sea during the third quarter of 2022. Production was negatively impacted by considerable planned and unplanned downtime at Beryl and Forties during the third quarter of 2022. North Sea production in the fourth quarter of 2022 is expected to improve following completion of these maintenance activities.

•The Company announced an oil discovery offshore Suriname at Baja-1 in Block 53 during the third quarter of 2022. Baja-1 was drilled to a depth of 5,290 meters and encountered 34 meters of net oil pay in a single interval within the Campanian. Preliminary fluid and log analysis indicates light oil with a gas-oil ratio of 1,600 to 2,200 standard cubic feet per barrel. Evaluation of open-hole well logs, cores, and reservoir fluids is ongoing. The Company also received regulatory approval regarding an amendment to the Block 53 Production Sharing Contract (PSC), which provides options to extend the exploration period of the PSC by up to four years. APA is the operator and holds a 45 percent interest in Block 53.

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

Revenue

The Company’s production revenues and respective contribution to total revenues by country were as follows:


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2022				2021				2022				2021
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution

	($ in millions)
Oil Revenues:
United States	$	630	38	%	$	484	41	%	$	1,883	36	%	$	1,325	40	%
Egypt(1)	739		44	%	465		39	%	2,431		46	%	1,299		39	%
North Sea	303		18	%	233		20	%	938		18	%	690		21	%
Total(1)	$	1,672	100	%	$	1,182	100	%	$	5,252	100	%	$	3,314	100	%

Natural Gas Revenues:
United States	$	300	70	%	$	188	64	%	$	764	62	%	$	533	64	%
Egypt(1)	84		20	%	63		22	%	270		22	%	198		24	%
North Sea	44		10	%	42		14	%	207		16	%	100		12	%
Total(1)	$	428	100	%	$	293	100	%	$	1,241	100	%	$	831	100	%

NGL Revenues:
United States	$	197	98	%	$	202	96	%	$	615	94	%	$	463	95	%
Egypt(1)	—		—	%	2		1	%	6		1	%	6		1	%
North Sea	5		2	%	6		3	%	33		5	%	16		4	%
Total(1)	$	202	100	%	$	210	100	%	$	654	100	%	$	485	100	%

Oil and Gas Revenues:
United States	$	1,127	49	%	$	874	52	%	$	3,262	46	%	$	2,321	50	%
Egypt(1)	823		36	%	530		31	%	2,707		38	%	1,503		33	%
North Sea	352		15	%	281		17	%	1,178		16	%	806		17	%
Total(1)	$	2,302	100	%	$	1,685	100	%	$	7,147	100	%	$	4,630	100	%

(1) Includes revenues attributable to a noncontrolling interest in Egypt.

Production

The Company’s production volumes by country were as follows:


	For the Quarter Ended September 30,			For the Nine Months Ended September 30,
	2022	Increase (Decrease)	2021	2022	Increase (Decrease)	2021
Oil Volume (b/d)
United States	72,351	(4)%	75,526	68,926	(9)%	75,384
Egypt(1)(2)	81,095	16%	69,830	83,857	18%	71,052
North Sea	25,160	(26)%	33,783	30,928	(15)%	36,398
Total	178,606	—%	179,139	183,711	—%	182,834

Natural Gas Volume (Mcf/d)
United States	489,107	(10)%	546,058	474,777	(11)%	531,695
Egypt(1)(2)	318,945	31%	243,294	350,400	35%	259,108
North Sea	18,822	(44)%	33,752	33,291	(17)%	40,061
Total	826,874	—%	823,104	858,468	3%	830,864

NGL Volume (b/d)
United States	64,958	(8)%	70,962	61,990	(6)%	65,805
Egypt(1)(2)	—	NM	496	261	(52)%	544
North Sea	558	(54)%	1,200	1,080	(11)%	1,220
Total	65,516	(10)%	72,658	63,331	(6)%	67,569

BOE per day(3)
United States	218,826	(8)%	237,498	210,045	(9)%	229,805
Egypt(1)(2)	134,253	21%	110,875	142,518	24%	114,780
North Sea(4)	28,855	(29)%	40,608	37,557	(15)%	44,295
Total	381,934	(2)%	388,981	390,120	—%	388,880

(1) Gross oil, natural gas, and NGL production in Egypt were as follows:


	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2022	2021	2022	2021
Oil (b/d)	133,607	134,128	136,476	134,976
Natural Gas (Mcf/d)	510,260	564,354	554,268	581,859
NGL (b/d)	—	776	397	846

(2) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:


	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2022	2021	2022	2021
Oil (b/d)	27,082	23,309	27,971	23,716
Natural Gas (Mcf/d)	106,553	81,309	116,869	86,564
NGL (b/d)	—	165	87	181

(3) The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

(4) Average sales volumes from the North Sea for the third quarters of 2022 and 2021 were 36,467 boe/d and 40,581 boe/d, respectively, and 39,362 boe/d and 45,637 boe/d for the first nine months of 2022 and 2021, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

NM — Not Meaningful

Pricing

The Company’s average selling prices by country were as follows:


	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2022		Increase (Decrease)	2021		2022		Increase (Decrease)	2021
Average Oil Price - Per barrel
United States	$	94.62	36%	$	69.69	$	100.06	55%	$	64.38
Egypt	99.04		37%	72.37		106.19		59%	66.97
North Sea	101.85		36%	74.94		105.59		58%	66.93
Total	97.81		36%	71.72		103.81		58%	65.90

Average Natural Gas Price - Per Mcf
United States	$	6.67	78%	$	3.75	$	5.89	60%	$	3.67
Egypt	2.87		2%	2.82		2.82		1%	2.80
North Sea	24.12		80%	13.40		24.59		169%	9.13
Total	5.62		45%	3.87		5.31		45%	3.66

Average NGL Price - Per barrel
United States	$	32.97	7%	$	30.85	$	36.36	41%	$	25.75
Egypt	—		NM	52.02		76.80		72%	44.73
North Sea	70.42		24%	56.64		72.86		51%	48.32
Total	33.39		6%	31.42		37.47		42%	26.32

NM — Not Meaningful

Third-Quarter 2022 compared to Third-Quarter 2021

Crude Oil Crude oil revenues for the third quarter of 2022 totaled $1.7 billion, a $490 million increase from the comparative 2021 quarter. A 36 percent increase in average realized prices primarily drove the increase in oil revenues compared to the prior-year quarter. Crude oil revenues accounted for 72 percent of total oil and gas production revenues and 47 percent of worldwide production in the third quarter of 2022. The Company’s worldwide oil production decreased 0.5 Mb/d to 178.6 Mb/d during the third quarter of 2022 from the comparative prior-year period, primarily a result of lower production in the North Sea due to longer operational downtime as compared to the third quarter of 2021 and natural production decline across all assets. These decreases were mostly offset by increased net production in Egypt resulting from improved cost recovery under the merged concession agreement ratified at the end of 2021.

Natural Gas Gas revenues for the third quarter of 2022 totaled $428 million, a $135 million increase from the comparative 2021 quarter. A 45 percent increase in average realized prices primarily drove the increase in natural gas revenues compared to the prior-year quarter. Natural gas revenues accounted for 19 percent of total oil and gas production revenues and 36 percent of worldwide production during the third quarter of 2022. The Company’s worldwide natural gas production increased 3.8 MMcf/d to 827 MMcf/d during the third quarter of 2022 from the comparative prior-year period, primarily a result of increased net production in Egypt resulting from improved cost recovery under the merged concession agreement ratified at the end of 2021. This increase was mostly offset by lower production in the North Sea due to longer operational downtime as compared to the third quarter of 2021, natural production decline across all assets, and the Company’s divestiture of non-core assets in the Permian Basin during the first quarter of 2022.

NGL NGL revenues for the third quarter of 2022 totaled $202 million, an $8 million decrease from the comparative 2021 quarter. A 6 percent increase in average realized prices increased third-quarter 2022 NGL revenues by $13 million compared to the prior-year quarter, while 10 percent lower average daily production decreased revenues by $21 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2022. The Company’s worldwide NGL production decreased 7.1 Mb/d to 65.5 Mb/d during the third quarter of 2022 from the comparative prior-year period, primarily a result of natural production decline across all assets and the Company’s divestiture of non-core assets in the Permian Basin during the first quarter of 2022.

Year-to-Date 2022 compared to Year-to-Date 2021

Crude Oil Crude oil revenues for the first nine months of 2022 totaled $5.3 billion, a $1.9 billion increase from the comparative 2021 period. A 58 percent increase in average realized prices increased oil revenues for the 2022 period by $1.9 billion compared to the prior-year period, while average daily production remained relatively flat compared to the prior-year period. Crude oil revenues accounted for 74 percent of total oil and gas production revenues and 47 percent of worldwide production for the first nine months of 2022. Crude oil prices realized during the first nine months of 2022 averaged $103.81 per barrel, compared to $65.90 per barrel in the comparative prior-year period. The Company’s worldwide oil production increased 0.9 Mb/d to 183.7 Mb/d in the first nine months of 2022 compared to the prior-year period, primarily a function of improved cost recovery under the merged concession agreement in Egypt ratified at the end of 2021, offset by operational downtime in the North Sea and natural production decline across all assets.

Natural Gas Gas revenues for the first nine months of 2022 totaled $1.2 billion, a $410 million increase from the comparative 2021 period. A 45 percent increase in average realized prices increased natural gas revenues for the 2022 period by $373 million compared to the prior-year period, while 3 percent higher average daily production increased revenues by $37 million compared to the prior-year period. Natural gas revenues accounted for 17 percent of total oil and gas production revenues and 37 percent of worldwide production for the first nine months of 2022. Natural gas prices realized during the first nine months of 2022 averaged $5.31 per Mcf, compared to $3.66 per Mcf in the comparative prior-year period. The Company’s worldwide natural gas production increased 28 MMcf/d to 858 MMcf/d in the first nine months of 2022 compared to the prior-year period, primarily a result of increased net production in Egypt resulting from improved cost recovery under the merged concession agreement ratified at the end of 2021, offset by operational downtime in the North Sea and natural production decline across all assets.

NGL NGL revenues for the first nine months of 2022 totaled $654 million, a $169 million increase from the comparative 2021 period. A 42 percent increase in average realized prices increased NGL revenues for the 2022 period by $206 million compared to the prior-year period, while 6 percent lower average daily production decreased revenues by $37 million compared to the prior-year period. NGL revenues accounted for 9 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2022. NGL prices realized during the first nine months of 2022 averaged $37.47 per barrel, compared to $26.32 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased 4.2 Mb/d to 63.3 Mb/d in the first nine months of 2022 compared to the prior-year period, primarily a result of natural production decline across all countries.

Altus Midstream Revenues

Prior to the deconsolidation of Altus on February 22, 2022, Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $35 million during the third quarter of 2021 and $16 million and $99 million during the first nine months of 2022 and 2021, respectively. These revenues were eliminated upon consolidation.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $585 million and $374 million during the third quarters of 2022 and 2021, respectively, and $1.5 billion and $1.1 billion during the first nine months of 2022 and 2021, respectively. Purchased oil and gas sales were offset by associated purchase costs of $573 million and $396 million during the third quarters of 2022 and 2021, respectively, and $1.5 billion and $1.2 billion during the first nine months of 2022 and 2021, respectively. Gross purchased oil and gas sales values were higher in the third quarter and first nine months of 2022 primarily due to higher average natural gas prices during the 2022 periods.

Operating Expenses

The Company’s operating expenses were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Lease operating expenses	$	364	$	316	$	1,067	$	891
Gathering, processing, and transmission	99		68		274		187
Purchased oil and gas costs	573		396		1,452		1,152
Taxes other than income	82		54		230		149
Exploration	95		34		193		109
General and administrative	69		70		314		239
Transaction, reorganization, and separation	4		4		21		8
Depreciation, depletion, and amortization:
Oil and gas property and equipment	300		306		847		940
Gathering, processing, and transmission assets	4		18		10		56
Other assets	6		11		22		32
Asset retirement obligation accretion	29		29		87		85
Impairments	—		18		—		18
Financing costs, net	75		205		303		422
Total Operating Expenses	$	1,700	$	1,529	$	4,820	$	4,288

Lease Operating Expenses (LOE)

LOE increased $48 million and $176 million in the third quarter and the first nine months of 2022, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 15 percent and 19 percent in the third quarter and the first nine months of 2022, respectively, from the comparative prior-year periods. The increase was driven by overall higher labor costs and operating costs trending with higher oil and gas prices and global inflation. These increases were coupled with overall higher workover activity in the U.S. and in the North Sea during the first nine months of 2022.

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,
	2022		2021		2022		2021

	(In millions)
Third-party processing and transmission costs	$	71	$	59	$	205	$	163
Midstream service costs - ALTM	—		35		18		98
Midstream service costs - Kinetik	28		—		64		—
Upstream processing and transmission costs	99		94		287		261
Midstream operating expenses	—		9		5		24
Intersegment eliminations	—		(35)		(18)		(98)
Total Gathering, processing, and transmission	$	99	$	68	$	274	$	187

GPT costs increased $31 million and $87 million in the third quarter and the first nine months of 2022, respectively, from the comparative prior-year periods. Third-party processing and transmission costs increased $12 million and $42 million in the third quarter and the first nine months of 2022, respectively, from the comparative prior-year periods. The increase in third-party costs for the third quarter and the first nine months of 2022 was primarily driven by an increase in average transportation rates during the year. Costs for services provided by ALTM in the first quarter of 2022 and 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) totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated. Midstream services provided by Kinetik totaled $28 million and $64 million in the third quarter and the first nine months of 2022, respectively.

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $573 million and $1.5 billion during the third quarter and the first nine months of 2022, respectively, compared to $396 million and $1.2 billion during the third quarter and the first nine months of 2021, respectively. Purchased oil and gas costs were offset by associated purchase sales of $585 million and $1.5 billion during the third quarter and the first nine months of 2022, respectively, compared to $374 million and $1.1 billion during the third quarter and the first nine months of 2021, respectively, as further discussed above.

Taxes Other Than Income

Taxes other than income increased $28 million and $81 million from the third quarter and the first nine months of 2021, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the same prior-year periods.

Exploration Expenses

The Company’s exploration expenses were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Unproved leasehold impairments	$	16	$	5	$	22	$	26
Dry hole expense	66		16		107		41
Geological and geophysical expense	1		4		19		14
Exploration overhead and other	12		9		45		28
Total Exploration	$	95	$	34	$	193	$	109

Exploration expenses increased $61 million and $84 million from the third quarter and the first nine months of 2021, respectively, primarily the result of higher dry hole expenses in Suriname and Egypt and exploration overhead, a function of increased exploration activities.

General and Administrative (G&A) Expenses

G&A expenses remained essentially flat compared to the third quarter of 2021 and increased $75 million compared to the first nine months of 2021. The increase in expenses for the first nine months of 2022 compared to the same prior-year period was primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price and anticipated achievement of performance and financial objectives as defined in the stock award plans. Higher overall wages across the Company and inflationary pressures also impacted G&A expenses compared to the prior-year period.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs remained flat compared to the third quarter of 2021 and increased $13 million from the first nine months of 2021. The increase in costs during the first nine months of 2022 compared to the same prior-year period was primarily a result of transaction costs from the BCP Business Combination.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties decreased $6 million and $93 million from the third quarter and the first nine months of 2021, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.19 per boe and $0.91 per boe from the third quarter and the first nine months of 2021, respectively. The decrease on an absolute basis was driven by lower depletion rates in Egypt, partially offset by higher production volumes.

Financing Costs, Net

The Company’s Financing costs were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2022		2021		2022		2021

	(In millions)
Interest expense	$	80	$	102	$	249	$	324
Amortization of debt issuance costs	1		1		8		6
Capitalized interest	(5)		(2)		(13)		(6)
Loss on extinguishment of debt	—		105		67		104
Interest income	(1)		(1)		(8)		(6)
Total Financing costs, net	$	75	$	205	$	303	$	422

Net financing costs decreased $130 million and $119 million from the third quarter and the first nine months of 2021, respectively. The lower overall interest expense was a result of the reduction of fixed-rate debt during 2021 and the first quarter of 2022. Additionally, losses incurred on the extinguishment of debt was lower during the first nine months of 2022 compared to the prior year period.

Provision for Income Taxes

The Company has recorded a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.

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. Significant commodity price decreases potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

The Company’s upstream capital investment for the third quarter of 2022 was slightly below its guidance for the period, and the Company expects its full-year estimated upstream capital investment to be approximately $1.725 billion. This is nearly 8 percent higher than initial guidance at the beginning of the year, primarily a result of increased drilling activity in Suriname.

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. As such, the Company believes it has sufficient resources to satisfy cash requirements over the next twelve months and beyond.

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, 2021.

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented:


	For the Nine Months Ended September 30,
	2022		2021

	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	3,530	$	2,411
Proceeds from Apache credit facility, net	—		290
Proceeds from Altus credit facility, net	—		33
Proceeds from asset divestitures	778		239
Proceeds from sale of Kinetik shares	224		—


Total Sources of Cash and Cash Equivalents	4,532		2,973
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	1,168	$	790

Acquisition of Delaware Basin properties	563		—
Leasehold and property acquisitions	30		6

Payments on revolving credit facilities, net	22		—
Payments on fixed-rate debt	1,370		1,795
Dividends paid to APA common stockholders	127		28
Distributions to noncontrolling interest - Egypt	237		203
Distributions to Altus Preferred Unit limited partners	11		34

Treasury stock activity, net	884		—
Deconsolidation of Altus cash and cash equivalents	143		—
Other	11		2
Total Uses of Cash and Cash Equivalents	4,566		2,858
Increase (decrease) in cash and cash equivalents	$	(34)	$	115

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 increased $1.1 billion from the first nine months of 2021, primarily due to higher commodity prices and associated revenues, partially offset by changes in working capital.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the statement of consolidated cash flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Proceeds from Apache Credit Facility, Net During the first nine months of 2021, Apache borrowed $290 million under its former revolving credit facility.

Proceeds from Asset Divestitures The Company received $778 million and $239 million of proceeds from the divestiture of certain non-core assets during the first nine months of 2022 and 2021, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first nine months of 2022. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.2 billion and $790 million during the first nine months of 2022 and 2021, respectively. The increase in capital investment is reflective of the increase in the Company’s capital program in the current year associated with higher cash flow from operations. The Company operated an average of 24 drilling rigs during the third quarter of 2022, compared to an average of 14 drilling rigs during the third quarter of 2021.

Acquisition of Delaware Basin Properties During the third quarter of 2022, the Company completed the acquisition of oil and gas assets in the Delaware Basin for approximately $593 million, subject to further post-closing adjustments. Cash consideration paid during the third quarter totaled $563 million, with final cash settlement anticipated to be completed during the fourth quarter of 2022.

Leasehold and Property Acquisitions During the first nine months of 2022 and 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $30 million and $6 million, respectively.

Payments on Revolving Credit Facilities APA and Apache paid down a net of $22 million during the first nine months of 2022 on their respective revolving credit facilities.

Payments on Fixed-Rate Debt 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% of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

During the quarter ended March 31, 2022, Apache 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.

In August 2021, Apache closed cash tender offers for certain outstanding notes and accepted for purchase $1.7 billion aggregate principal amount of certain notes. Apache paid holders an aggregate $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $98 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During the first nine months of 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

The Company expects that Apache intends to reduce debt outstanding under its indentures from time to time.

Dividends The Company paid $127 million and $28 million during the first nine months of 2022 and 2021, respectively, for dividends on its common stock. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625 and, in the fourth quarter of 2021, a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend 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 $237 million and $203 million during the first nine months of 2022 and 2021, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Prior to the deconsolidation of Altus on February 22, 2022, Altus Midstream LP paid $11 million and $34 million in cash distributions to its limited partners holding Preferred Units during the first nine months of 2022 and 2021. For more information regarding the Preferred Units, refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Treasury Stock Activity, net In the first nine months of 2022, the Company repurchased 24.0 million shares at an average price of $36.78 per share totaling $884 million, and as of September 30, 2022, the Company had remaining authorization to repurchase 64.8 million shares. No shares were repurchased during the nine months ended September 30, 2021.

Liquidity

The following table presents a summary of the Company’s key financial indicators:


	September 30, 2022		December 31, 2021

	(In millions)
Cash and cash equivalents	$	268	$	302
Total debt - Apache	5,529		6,853
Total debt - Altus	—		657
Total equity (deficit)	1,551		(717)
Available committed borrowing capacity under syndicated credit facilities	2,100		2,426
Available committed borrowing capacity - Altus	—		141

Cash and Cash Equivalents As of September 30, 2022, the Company had $268 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of September 30, 2022, the Company had $5.5 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of September 30, 2022, current debt included $123 million, carrying value, of Apache’s 2.625% senior notes due January 15, 2023 and $2 million of finance lease obligations. During the quarter ended September 30, 2022, Apache notified holders of its 2.625% notes due 2023 that Apache elected to redeem the notes on October 17, 2022, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption, including the $123 million outstanding principal amount of the notes, was financed in part by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

Committed Credit Facilities On April 29, 2022, the Company entered into two syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 syndicated credit agreement (the Former Facility).

Uncommitted Credit Facilities Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2022 and December 31, 2021, there were no outstanding borrowings under these facilities. As of September 30, 2022 and December 31, 2021, there were £117 million and $17 million in letters of credit outstanding under these facilities.

Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit backed by investment-grade counterparties to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, respectively, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently required to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

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, 2021. 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, 2021.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. These factors have only been heightened as uncertainties in the commodity and financial markets associated with the COVID-19 pandemic, the conflict in Ukraine, global inflation, and other current events continue to impact oil and gas supply and demand. The Company continually monitors its market risk exposure.

The Company’s average crude oil price realizations increased 36 percent from $71.72 per barrel to $97.81 per barrel during the third quarters of 2021 and 2022, respectively. The Company’s average natural gas price realizations increased 45 percent from $3.87 per Mcf to $5.62 per Mcf during the third quarters of 2021 and 2022, respectively. The Company’s average NGL price realizations increased 6 percent from $31.42 per barrel to $33.39 per barrel during the third quarters of 2021 and 2022, respectively. Based on average daily production for the third quarter of 2022, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $16 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6 million.

The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2022, the Company had open natural gas derivatives not designated as cash flow hedges in a liability position with a fair value of $88 million. A 10 percent increase in gas prices would increase the liability by approximately $24 million, while a 10 percent decrease in prices would decrease the liability by approximately $24 million. These fair value changes assume volatility based on prevailing market parameters as of September 30, 2022. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

As of September 30, 2022, the Company had $5.0 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.25 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.

The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the indentures and credit facilities. As of September 30, 2022, the Company had approximately $268 million in cash and cash equivalents, approximately 39 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2022, there were $520 million of borrowings outstanding under the Company’s syndicated revolving credit facilities. A change in the interest rate applicable to short-term investments and credit facility borrowings would 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 primarily 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.

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. Excluding the impacts of the foreign exchange contracts discussed below, foreign currency net gain or loss of $6 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2022.

The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. As of September 30, 2022, the Company had outstanding foreign exchange contracts not designated as cash flow hedges with a total notional amount of £45 million in a liability position with a fair value of $8 million. A 10 percent strengthening of the British pound against the U.S. dollar would decrease the liability by approximately $4 million, while a 10 percent weakening of the British pound against the U.S. dollar would increase the liability by approximately $5 million.

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, 2022, 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, 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021 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

Except as set forth herein, 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, 2021.

Given the nature of its business, Apache Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2022, June 30, 2022, and September 30, 2022 and Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS

Newly enacted U.S. tax legislation may adversely affect the Company’s financial condition and cash flows.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). Among other changes, the IRA introduced a new 15 percent corporate alternative minimum tax (Corporate AMT) for taxable years beginning after December 31, 2022 on applicable corporations with an average annual adjusted financial statement income (AFSI) that exceeds $1.0 billion for any three consecutive tax years preceding the tax year at issue. If the Company were to meet this average AFSI test, any resulting Corporate AMT liability could adversely affect the Company’s future financial results, including earnings and cash flows. Additionally, the IRA introduced a 1 percent excise tax on the fair market value of applicable stock repurchases after December 31, 2022. The impact of this provision will be dependent on the extent of any share repurchases made by the Company in future periods and could adversely affect the Company’s future financial condition and cash flows.

RISKS RELATED TO CLIMATE CHANGE

The impacts of energy transition could adversely affect the Company’s business, operating results, and financial condition.

In recent years, increasing attention has been given to corporate activities related to climate change and energy transition. This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in:

•increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power;

•technological advances with respect to the generation, transmission, storage, and consumption of alternative energy sources; and

•development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more efficient products and services.

These developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for the Company’s, and in turn the prices it receives for its, crude oil, natural gas, and NGL production, which could materially and adversely affect the Company’s business and financial performance.

The treatment and disposal of produced water is becoming more highly regulated and restricted and could expose the Company to additional costs or limit certain operations.

The treatment and disposal of produced water is becoming more highly regulated and restricted. The Company’s ability to accurately report and track its water use is necessary for its continued ability to reuse and recycle water, when possible. While the Company remains focused on reusing or recycling water over disposal of water, the Company’s costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water may increase the Company’s operating costs, which could materially and adversely affect its business, results of operations, and financial conditions.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, the Railroad Commission of Texas (RRC) has been developing data associated with seismic activity, particularly such activity related to injection wells used for produced water disposal. In September 2021, the RRC began to limit saltwater disposal in the Midland Basin under what is known as a Seismic Response Action (or SAR) due to increased seismic activity.

Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal. These developments could result in restriction of disposal wells that could have a material effect on the Company’s capital expenses and operating costs or limit production in certain areas.

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, 2022:


Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(1)
July 1 to July 31, 2022	6,863,858	$	33.88	6,863,858	27,714,783
August 1 to August 31, 2022	2,958,437	33.81		2,958,437	24,756,346
September 1 to September 30, 2022	—	—		—	64,756,346
Total	9,822,295	$	33.86

(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 6. EXHIBITS


2.1	–	Agreement and Plan of Merger, dated as of March 1, 2021, by and among Apache Corporation, Registrant, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.1	–	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.2	–	Amended and Restated Bylaws of Registrant, dated September 14, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 20, 2021, SEC File No. 001-40144).
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
**32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101	–	The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2022, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.SCH	–	Inline XBRL Taxonomy Schema Document.
*101.CAL	–	Inline XBRL Calculation Linkbase Document.
*101.DEF	–	Inline XBRL Definition Linkbase Document.
*101.LAB	–	Inline XBRL Label Linkbase Document.
*101.PRE	–	Inline XBRL Presentation Linkbase Document.
*104	–	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith

** Furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


		APA CORPORATION

Dated:	November 3, 2022	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	November 3, 2022	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

Document

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2022


/s/ John J. Christmann IV
John J. Christmann IV
Chief Executive Officer and President
(principal executive officer)

Document

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of APA Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 3, 2022


/s/ Stephen J. Riney
Stephen J. Riney
Executive Vice President and Chief Financial Officer
(principal financial officer)

Document

EXHIBIT 32.1

APA CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2022, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 3, 2022


/s/ John J. Christmann IV
By:						John J. Christmann IV
Title:						Chief Executive Officer and President
						(principal executive officer)

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 2022, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of APA Corporation.

Date: November 3, 2022


/s/ Stephen J. Riney
By:						Stephen J. Riney
Title:						Executive Vice President and Chief Financial Officer
						(principal financial officer)