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 June 30, ~~2021~~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 July 31, ~~2021~~2022			~~378,021,539~~326,530,252

TABLE OF CONTENTS


Item	Item		Page	Item		Page

		PART I - FINANCIAL INFORMATION			PART I - FINANCIAL INFORMATION
1.	1.	FINANCIAL STATEMENTS	1	1.	FINANCIAL STATEMENTS	1
		STATEMENT OF CONSOLIDATED OPERATIONS	1		STATEMENT OF CONSOLIDATED OPERATIONS	1
		STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)	2		STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)	2
		STATEMENT OF CONSOLIDATED CASH FLOWS	3		STATEMENT OF CONSOLIDATED CASH FLOWS	3
		CONSOLIDATED BALANCE SHEET	4		CONSOLIDATED BALANCE SHEET	4
		STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST	5		STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTERESTS	5
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30	2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
3.	3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43	3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
4.	4.	CONTROLS AND PROCEDURES	44	4.	CONTROLS AND PROCEDURES	46

		PART II - OTHER INFORMATION			PART II - OTHER INFORMATION
1.	1.	LEGAL PROCEEDINGS	45	1.	LEGAL PROCEEDINGS	48
1A.	1A.	RISK FACTORS	45	1A.	RISK FACTORS	48
2.	2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45	2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	48

6.	6.	EXHIBITS	46	6.	EXHIBITS	49

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, ~~2020,~~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,” “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 ~~variant)~~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;~~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 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 ~~of Apache Corporation, the Company’s predecessor registrant,~~ for the fiscal year ended December 31, ~~2020;~~2021;

•other risks and uncertainties disclosed in the Company’s second-quarter ~~2021~~2022 earnings release;

•~~other factors disclosed under Part II, Item 1A—Risk Factors in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021;~~

•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 ~~the~~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 ~~natural gas liquids~~NGLs per day.

“bbl” or “bbls” means barrel or barrels of oil or ~~natural gas liquids.~~NGLs.

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

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

“boe/d” means boe per day.

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

“Liquids” means oil and ~~natural gas liquids.~~NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or ~~natural gas liquids.~~NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or ~~natural gas liquids.~~NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

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

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

With respect to information relating to ~~our~~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 ~~our~~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~~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 June 30,				For the Six Months Ended June 30,
		For the Quarter Ended June 30,				For the Six Months Ended June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions, except share data)									(In millions, except share data)
REVENUES AND OTHER:	REVENUES AND OTHER:									REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	Oil, natural gas, and natural gas liquids production revenues	$	1,514	$	697	$	2,945	$	1,933	Oil, natural gas, and natural gas liquids production revenues	$	2,525	$	1,514	$	4,845	$	2,945
Purchased oil and gas sales	Purchased oil and gas sales	242		55		682		163		Purchased oil and gas sales	522		242		871		682
Total revenues	Total revenues	1,756		752		3,627		2,096		Total revenues	3,047		1,756		5,716		3,627
Derivative instrument gains (losses), net	Derivative instrument gains (losses), net	(113)		(175)		45		(278)		Derivative instrument gains (losses), net	(32)		(113)		(94)		45
Gain on divestitures, net		65		0		67		25
Gain (loss) on divestitures, net										Gain (loss) on divestitures, net	(27)		65		1,149		67

Other, net	Other, net	74		19		135		32		Other, net	64		74		109		135
		1,782		596		3,874		1,875			3,052		1,782		6,880		3,874
OPERATING EXPENSES:	OPERATING EXPENSES:									OPERATING EXPENSES:
Lease operating expenses	Lease operating expenses	311		264		575		599		Lease operating expenses	359		311		703		575
Gathering, processing, and transmission		61		72		119		143
Gathering, processing, and transmission(1)										Gathering, processing, and transmission(1)	94		61		175		119
Purchased oil and gas costs	Purchased oil and gas costs	262		46		756		132		Purchased oil and gas costs	528		262		879		756
Taxes other than income	Taxes other than income	51		23		95		56		Taxes other than income	78		51		148		95
Exploration	Exploration	26		72		75		129		Exploration	56		26		98		75
General and administrative	General and administrative	86		94		169		162		General and administrative	89		86		245		169
Transaction, reorganization, and separation	Transaction, reorganization, and separation	4		10		4		37		Transaction, reorganization, and separation	3		4		17		4
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	351		418		693		984		Depreciation, depletion, and amortization	278		351		569		693
Asset retirement obligation accretion	Asset retirement obligation accretion	28		27		56		54		Asset retirement obligation accretion	29		28		58		56
Impairments		0		20		0		4,492

Financing costs, net	Financing costs, net	107		(34)		217		69		Financing costs, net	76		107		228		217
		1,287		1,012		2,759		6,857			1,590		1,287		3,120		2,759
NET INCOME (LOSS) BEFORE INCOME TAXES		495		(416)		1,115		(4,982)
Current income tax provision (benefit)		131		(27)		280		62
NET INCOME BEFORE INCOME TAXES										NET INCOME BEFORE INCOME TAXES	1,462		495		3,760		1,115
Current income tax provision										Current income tax provision	415		131		807		280
Deferred income tax benefit	Deferred income tax benefit	(44)		(11)		(23)		(44)		Deferred income tax benefit	(20)		(44)		(60)		(23)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS		408		(378)		858		(5,000)
Net income (loss) attributable to noncontrolling interest - Egypt		41		(11)		83		(162)
Net income (loss) attributable to noncontrolling interest - Altus		27		0		28		(9)
Net income attributable to Altus Preferred Unit limited partners		24		19		43		37
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK		$	316	$	(386)	$	704	$	(4,866)
NET INCOME INCLUDING NONCONTROLLING INTERESTS										NET INCOME INCLUDING NONCONTROLLING INTERESTS	1,067		408		3,013		858
Net income attributable to noncontrolling interest - Egypt										Net income attributable to noncontrolling interest - Egypt	141		41		260		83
Net income attributable to noncontrolling interest - Altus										Net income attributable to noncontrolling interest - Altus	—		27		14		28
Net income (loss) attributable to Altus Preferred Unit limited partners										Net income (loss) attributable to Altus Preferred Unit limited partners	—		24		(70)		43
NET INCOME ATTRIBUTABLE TO COMMON STOCK										NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	926	$	316	$	2,809	$	704

NET INCOME (LOSS) PER COMMON SHARE:

NET INCOME PER COMMON SHARE:										NET INCOME PER COMMON SHARE:
Basic	Basic	$	0.83	$	(1.02)	$	1.86	$	(12.88)	Basic	$	2.72	$	0.83	$	8.18	$	1.86

Diluted	Diluted	$	0.82	$	(1.02)	$	1.86	$	(12.88)	Diluted	$	2.71	$	0.82	$	8.15	$	1.86
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:	WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:									WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	Basic	378		378		378		378		Basic	341		378		344		378
Diluted	Diluted	379		378		379		378		Diluted	342		379		344		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
June 30,
For the Six Months Ended
June 30,
2021 2020 2021 2020
(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS $ 408 $ (378) $ 858 $ (5,000)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Share of equity method interests other comprehensive income (loss) — 0 1 (1)
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS 408 (378) 859 (5,001)
Comprehensive income (loss) attributable to noncontrolling interest - Egypt 41 (11) 83 (162)
Comprehensive income (loss) attributable to noncontrolling interest - Altus 27 0 28 (9)
Comprehensive income attributable to Altus Preferred Unit limited partners 24 19 43 37
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK $ 316 $ (386) $ 705 $ (4,867)


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021

	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$	1,067	$	408	$	3,013	$	858
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Share of equity method interests other comprehensive income	—		—		—		1
Pension and postretirement benefit plan	—		—		(1)		—
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	1,067		408		3,012		859
Comprehensive income attributable to noncontrolling interest - Egypt	141		41		260		83
Comprehensive income attributable to noncontrolling interest - Altus	—		27		14		28
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners	—		24		(70)		43
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	926	$	316	$	2,808	$	705

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


							For the Six Months Ended June 30,
		For the Six Months Ended June 30,					2022		2021
		2021		2020
		(In millions)					(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:	CASH FLOWS FROM OPERATING ACTIVITIES:					CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests		$	858	$	(5,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income including noncontrolling interests						Net income including noncontrolling interests	$	3,013	$	858
Adjustments to reconcile net income to net cash provided by operating activities:						Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument losses, net	Unrealized derivative instrument losses, net	55		241		Unrealized derivative instrument losses, net	83		55
Gain on divestitures, net	Gain on divestitures, net	(67)		(25)		Gain on divestitures, net	(1,149)		(67)
Exploratory dry hole expense and unproved leasehold impairments	Exploratory dry hole expense and unproved leasehold impairments	46		97		Exploratory dry hole expense and unproved leasehold impairments	47		46
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	693		984		Depreciation, depletion, and amortization	569		693
Asset retirement obligation accretion	Asset retirement obligation accretion	56		54		Asset retirement obligation accretion	58		56
Impairments		0		4,492
Deferred income tax benefit		(23)		(44)
Gain on extinguishment of debt		(1)		(140)

Benefit from deferred income taxes						Benefit from deferred income taxes	(60)		(23)
(Gain) loss on extinguishment of debt						(Gain) loss on extinguishment of debt	67		(1)

Other, net	Other, net	(14)		14		Other, net	(88)		(14)
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Receivables	Receivables	(165)		183		Receivables	(519)		(165)
Inventories	Inventories	20		25		Inventories	(18)		20
Drilling advances and other current assets	Drilling advances and other current assets	43		(26)		Drilling advances and other current assets	28		43
Deferred charges and other long-term assets	Deferred charges and other long-term assets	(18)		(16)		Deferred charges and other long-term assets	(11)		(18)
Accounts payable	Accounts payable	157		(147)		Accounts payable	206		157
Accrued expenses	Accrued expenses	17		(148)		Accrued expenses	202		17
Deferred credits and noncurrent liabilities	Deferred credits and noncurrent liabilities	(17)		42		Deferred credits and noncurrent liabilities	(2)		(17)
NET CASH PROVIDED BY OPERATING ACTIVITIES	NET CASH PROVIDED BY OPERATING ACTIVITIES	1,640		586		NET CASH PROVIDED BY OPERATING ACTIVITIES	2,426		1,640
CASH FLOWS FROM INVESTING ACTIVITIES:	CASH FLOWS FROM INVESTING ACTIVITIES:					CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	Additions to upstream oil and gas property	(558)		(838)		Additions to upstream oil and gas property	(741)		(558)
Additions to Altus gathering, processing, and transmission (GPT) facilities		(1)		(25)

Leasehold and property acquisitions	Leasehold and property acquisitions	(3)		(3)		Leasehold and property acquisitions	(26)		(3)
Contributions to Altus equity method interests		(24)		(154)

Proceeds from sale of oil and gas properties	Proceeds from sale of oil and gas properties	181		126		Proceeds from sale of oil and gas properties	751		181
Proceeds from sale of Kinetik shares						Proceeds from sale of Kinetik shares	224		—
Deconsolidation of Altus cash and cash equivalents						Deconsolidation of Altus cash and cash equivalents	(143)		—
Other, net	Other, net	12		(23)		Other, net	(49)		(13)
NET CASH USED IN INVESTING ACTIVITIES		(393)		(917)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES						NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	16		(393)
CASH FLOWS FROM FINANCING ACTIVITIES:	CASH FLOWS FROM FINANCING ACTIVITIES:					CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) Apache credit facility, net		(150)		565
Payments on revolving credit facilities, net						Payments on revolving credit facilities, net	(267)		(150)
Proceeds from Altus credit facility, net	Proceeds from Altus credit facility, net	33		97		Proceeds from Altus credit facility, net	—		33

Payments on Apache fixed-rate debt	Payments on Apache fixed-rate debt	(20)		(264)		Payments on Apache fixed-rate debt	(1,370)		(20)
Distributions to noncontrolling interest - Egypt	Distributions to noncontrolling interest - Egypt	(60)		(40)		Distributions to noncontrolling interest - Egypt	(159)		(60)
Distributions to Altus Preferred Unit limited partners	Distributions to Altus Preferred Unit limited partners	(23)		0		Distributions to Altus Preferred Unit limited partners	(11)		(23)

Treasury stock activity, net						Treasury stock activity, net	(552)		—
Dividends paid to APA common stockholders	Dividends paid to APA common stockholders	(19)		(104)		Dividends paid to APA common stockholders	(86)		(19)
Other, net	Other, net	(21)		(35)		Other, net	(17)		(21)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(260)		219
NET CASH USED IN FINANCING ACTIVITIES						NET CASH USED IN FINANCING ACTIVITIES	(2,462)		(260)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	987		(112)		NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(20)		987
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262		247		CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	302		262
CASH AND CASH EQUIVALENTS AT END OF PERIOD	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,249	$	135	CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	282	$	1,249

SUPPLEMENTARY CASH FLOW DATA:	SUPPLEMENTARY CASH FLOW DATA:					SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	Interest paid, net of capitalized interest	$	233	$	212	Interest paid, net of capitalized interest	$	172	$	233
Income taxes paid, net of refunds	Income taxes paid, net of refunds	231		80		Income taxes paid, net of refunds	637		231

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

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


							June 30, 2022(1)		December 31, 2021(1)
		June 30, 2021		December 31, 2020
		(In millions, except share data)					(In millions, except share data)
ASSETS	ASSETS					ASSETS
CURRENT ASSETS:	CURRENT ASSETS:					CURRENT ASSETS:
Cash and cash equivalents ($75 and $24 related to Altus VIE)		$	1,249	$	262
Receivables, net of allowance of $99 and $95		1,068		908
Other current assets (Note 5) ($9 and $5 related to Altus VIE)		628		676
Cash and cash equivalents ($132 related to Altus VIE)						Cash and cash equivalents ($132 related to Altus VIE)	$	282	$	302
Receivables, net of allowance of $115 and $109						Receivables, net of allowance of $115 and $109	1,894		1,394
Other current assets (Note 5) ($9 related to Altus VIE)						Other current assets (Note 5) ($9 related to Altus VIE)	907		684
		2,945		1,846			3,083		2,380
PROPERTY AND EQUIPMENT:	PROPERTY AND EQUIPMENT:					PROPERTY AND EQUIPMENT:
Oil and gas properties	Oil and gas properties	40,437		41,819		Oil and gas properties	40,936		40,749
Gathering, processing, and transmission facilities ($209 related to Altus VIE)						Gathering, processing, and transmission facilities ($209 related to Altus VIE)	447		673
Other ($3 related to Altus VIE)						Other ($3 related to Altus VIE)	604		1,126
Less: Accumulated depreciation, depletion, and amortization ($25 related to Altus VIE)						Less: Accumulated depreciation, depletion, and amortization ($25 related to Altus VIE)	(33,756)		(34,213)
							8,231		8,335
OTHER ASSETS:						OTHER ASSETS:
Equity method interests (Note 6) ($1,365 related to Altus VIE)						Equity method interests (Note 6) ($1,365 related to Altus VIE)	618		1,365
Decommissioning security for sold Gulf of Mexico properties (Note 11)						Decommissioning security for sold Gulf of Mexico properties (Note 11)	383		640
Deferred charges and other ($6 related to Altus VIE)						Deferred charges and other ($6 related to Altus VIE)	609		583
							$	12,924	$	13,303

Gathering, processing, and transmission facilities ($206 and $206 related to Altus VIE)		668		670
Other ($4 and $3 related to Altus VIE)		1,140		1,140
Less: Accumulated depreciation, depletion, and amortization ($19 and $13 related to Altus VIE)		(33,744)		(34,810)
LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY (DEFICIT)						LIABILITIES, NONCONTROLLING INTERESTS, AND EQUITY (DEFICIT)
CURRENT LIABILITIES:						CURRENT LIABILITIES:
Accounts payable ($12 related to Altus VIE)						Accounts payable ($12 related to Altus VIE)	$	925	$	731
Current debt						Current debt	125		215
Other current liabilities (Note 7) ($15 related to Altus VIE)						Other current liabilities (Note 7) ($15 related to Altus VIE)	1,763		1,171
		8,501		8,819			2,813		2,117
OTHER ASSETS:
Equity method interests (Note 6) ($1,554 and $1,555 related to Altus VIE)		1,554		1,555
Deferred charges and other ($9 and $5 related to Altus VIE)		512		526
		$	13,512	$	12,746

LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	603	$	444
Current debt		215		2
Other current liabilities (Note 7) ($11 and $4 related to Altus VIE)		955		862
		1,773		1,308
LONG-TERM DEBT (Note 9) ($657 and $624 related to Altus VIE)		8,420		8,770
LONG-TERM DEBT (Note 9) ($657 related to Altus VIE)						LONG-TERM DEBT (Note 9) ($657 related to Altus VIE)	5,160		7,295
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:	DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:					DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	Income taxes	194		215		Income taxes	89		148
Asset retirement obligation (Note 8) ($66 and $64 related to Altus VIE)		1,893		1,888
Other ($131 and $144 related to Altus VIE)		539		602
Asset retirement obligation (Note 8) ($68 related to Altus VIE)						Asset retirement obligation (Note 8) ($68 related to Altus VIE)	2,061		2,089
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)						Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	825		1,086
Other ($67 related to Altus VIE)						Other ($67 related to Altus VIE)	471		573
		2,626		2,705			3,446		3,896
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	617		608		REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	—		712
EQUITY (DEFICIT):	EQUITY (DEFICIT):					EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 418,960,548 and 418,429,375 shares issued, respectively		262		262
Common stock, $0.625 par, 860,000,000 shares authorized, 419,756,641 and 419,078,606 shares issued, respectively						Common stock, $0.625 par, 860,000,000 shares authorized, 419,756,641 and 419,078,606 shares issued, respectively	262		262
Paid-in capital	Paid-in capital	11,704		11,735		Paid-in capital	11,567		11,645
Accumulated deficit	Accumulated deficit	(9,757)		(10,461)		Accumulated deficit	(6,679)		(9,488)
Treasury stock, at cost, 40,943,612 and 40,946,745 shares, respectively		(3,188)		(3,189)
Treasury stock, at cost, 86,362,994 and 72,147,841 shares, respectively						Treasury stock, at cost, 86,362,994 and 72,147,841 shares, respectively	(4,587)		(4,036)
Accumulated other comprehensive income	Accumulated other comprehensive income	15		14		Accumulated other comprehensive income	21		22
APA SHAREHOLDERS’ DEFICIT		(964)		(1,639)
APA SHAREHOLDERS’ EQUITY (DEFICIT)						APA SHAREHOLDERS’ EQUITY (DEFICIT)	584		(1,595)
Noncontrolling interest - Egypt	Noncontrolling interest - Egypt	948		925		Noncontrolling interest - Egypt	921		820
Noncontrolling interest - Altus	Noncontrolling interest - Altus	92		69		Noncontrolling interest - Altus	—		58
TOTAL EQUITY (DEFICIT)	TOTAL EQUITY (DEFICIT)	76		(645)		TOTAL EQUITY (DEFICIT)	1,505		(717)
		$	13,512	$	12,746		$	12,924	$	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 ~~INTEREST~~INTERESTS

(Unaudited)


		Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income (Loss)		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)			Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)
		(In millions)
For the Quarter Ended June 30, 2020
Balance at March 31, 2020		$	573	$	262	$	11,747	$	(10,081)	$	(3,189)	$	15	$	(1,246)	$	1,018	$	(228)
Net loss attributable to common stock		—		—		—		(386)		—		—		(386)		—		(386)
Net loss attributable to noncontrolling interest - Egypt		—		—		—		—		—		—		—		(11)		(11)

Net income attributable to Altus Preferred Unit holders		19		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt		—		—		—		—		—		—		—		(8)		(8)
Common dividends declared ($0.025 per share)		—		—		(9)		—		—		—		(9)		—		(9)
Other		—		—		6		—		—		—		6		—		6
Balance at June 30, 2020		$	592	$	262	$	11,744	$	(10,467)	$	(3,189)	$	15	$	(1,635)	$	999	$	(636)
																					(In millions)
For the Quarter Ended June 30, 2021	For the Quarter Ended June 30, 2021																			For the Quarter Ended June 30, 2021
Balance at March 31, 2021	Balance at March 31, 2021	$	605	$	262	$	11,727	$	(10,073)	$	(3,189)	$	15	$	(1,258)	$	997	$	(261)	Balance at March 31, 2021	$	605	$	262	$	11,727	$	(10,073)	$	(3,189)	$	15	$	(1,258)	$	997	$	(261)
Net income attributable to common stock	Net income attributable to common stock	—		—		—		316		—		—		316		—		316		Net income attributable to common stock	—		—		—		316		—		—		316		—		316
Net income attributable to noncontrolling interest - Egypt	Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		41		41		Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		41		41
Net income attributable to noncontrolling interest - Altus	Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		27		27		Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		27		27
Net income attributable to Altus Preferred Unit limited partners		24		—		—		—		—		—		—		—		—
Net income attributable to Altus Preferred Unit holders																				Net income attributable to Altus Preferred Unit holders	24		—		—		—		—		—		—		—		—

Distributions payable to Altus Preferred Unit limited partners	Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—		Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—

Distributions to noncontrolling interest - Egypt	Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(20)		(20)		Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(20)		(20)
Common dividends declared ($0.025 per share)	Common dividends declared ($0.025 per share)	—		—		(10)		—		—		—		(10)		—		(10)		Common dividends declared ($0.025 per share)	—		—		(10)		—		—		—		(10)		—		(10)
Other	Other	—		—		(13)		—		1		—		(12)		(5)		(17)		Other	—		—		(13)		—		1		—		(12)		(5)		(17)
Balance at June 30, 2021	Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76	Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76

For the Quarter Ended June 30, 2022																				For the Quarter Ended June 30, 2022
Balance at March 31, 2022																				Balance at March 31, 2022	$	—	$	262	$	11,600	$	(7,605)	$	(4,296)	$	21	$	(18)	$	870	$	852
Net income attributable to common stock																				Net income attributable to common stock	—		—		—		926		—		—		926		—		926
Net income attributable to noncontrolling interest - Egypt																				Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		141		141

Distributions to noncontrolling interest - Egypt																				Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(90)		(90)
Common dividends declared ($0.125 per share)																				Common dividends declared ($0.125 per share)	—		—		(42)		—		—		—		(42)		—		(42)
Treasury stock activity, net																				Treasury stock activity, net	—		—		—		—		(291)		—		(291)		—		(291)

Other																				Other	—		—		9		—		—		—		9		—		9
Balance at June 30, 2022																				Balance at June 30, 2022	$	—	$	262	$	11,567	$	(6,679)	$	(4,587)	$	21	$	584	$	921	$	1,505

(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 ~~INTEREST~~INTERESTS - Continued

(Unaudited)


		Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income (Loss)		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)			Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners(1)		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests(1)		TOTAL EQUITY (DEFICIT)
		(In millions)
For the Six Months Ended June 30, 2020
Balance at December 31, 2019		$	555	$	261	$	11,769	$	(5,601)	$	(3,190)	$	16	$	3,255	$	1,210	$	4,465
Net loss attributable to common stock		—		—		—		(4,866)		—		—		(4,866)		—		(4,866)
Net loss attributable to noncontrolling interest - Egypt		—		—		—		—		—		—		—		(162)		(162)
Net loss attributable to noncontrolling interest - Altus		—		—		—		—		—		—		—		(9)		(9)

Net income attributable to Altus Preferred Unit holders		37		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt		—		—		—		—		—		—		—		(40)		(40)
Common dividends declared ($0.025 per share)		—		—		(19)		—		—		—		(19)		—		(19)
Other		—		1		(6)		—		1		(1)		(5)		—		(5)
Balance at June 30, 2020		$	592	$	262	$	11,744	$	(10,467)	$	(3,189)	$	15	$	(1,635)	$	999	$	(636)
																					(In millions)
For the Six Months Ended June 30, 2021	For the Six Months Ended June 30, 2021																			For the Six Months Ended June 30, 2021
Balance at December 31, 2020	Balance at December 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)	Balance at December 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)
Net income attributable to common stock	Net income attributable to common stock	—		—		—		704		—		—		704		—		704		Net income attributable to common stock	—		—		—		704		—		—		704		—		704
Net income attributable to noncontrolling interest - Egypt	Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		83		83		Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		83		83
Net income attributable to noncontrolling interest - Altus	Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		28		28		Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		28		28
Net income attributable to Altus Preferred Unit limited partners		43		—		—		—		—		—		—		—		—
Net income attributable to Altus Preferred Unit holders																				Net income attributable to Altus Preferred Unit holders	43		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	Distributions payable to Altus Preferred Unit limited partners	(11)		—		—		—		—		—		—		—		—		Distributions payable to Altus Preferred Unit limited partners	(11)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	Distributions paid to Altus Preferred Unit limited partners	(23)		—		—		—		—		—		—		—		—		Distributions paid to Altus Preferred Unit limited partners	(23)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(60)		(60)		Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(60)		(60)
Common dividends declared ($0.025 per share)		—		—		(19)		—		—		—		(19)		—		(19)
Common dividends declared ($0.05 per share)																				Common dividends declared ($0.05 per share)	—		—		(19)		—		—		—		(19)		—		(19)
Other	Other	—		—		(12)		—		1		1		(10)		(5)		(15)		Other	—		—		(12)		—		1		1		(10)		(5)		(15)
Balance at June 30, 2021	Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76	Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76

For the Six Months Ended June 30, 2022																				For the Six Months Ended June 30, 2022
Balance at December 31, 2021																				Balance at December 31, 2021	$	712	$	262	$	11,645	$	(9,488)	$	(4,036)	$	22	$	(1,595)	$	878	$	(717)
Net income attributable to common stock																				Net income attributable to common stock	—		—		—		2,809		—		—		2,809		—		2,809
Net income attributable to noncontrolling interest - Egypt																				Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		260		260
Net income attributable to noncontrolling interest - Altus																				Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		14		14
Net loss attributable to Altus Preferred Unit limited partners																				Net loss attributable to Altus Preferred Unit limited partners	(70)		—		—		—		—		—		—		—		—

Distributions to noncontrolling interest - Egypt																				Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(159)		(159)
Common dividends declared ($0.25 per share)																				Common dividends declared ($0.25 per share)	—		—		(85)		—		—		—		(85)		—		(85)
Deconsolidation of Altus																				Deconsolidation of Altus	(642)		—		—		—		—		—		—		(72)		(72)
Treasury stock activity, net																				Treasury stock activity, net	—		—		—		—		(551)		—		(551)		—		(551)
Other																				Other	—		—		7		—		—		(1)		6		—		6
Balance at June 30, 2022																				Balance at June 30, 2022	$	—	$	262	$	11,567	$	(6,679)	$	(4,587)	$	21	$	584	$	921	$	1,505

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 ~~of Apache Corporation, the Company’s predecessor registrant,~~ for the fiscal year ended December 31, ~~2020,~~2021, which contains a summary of the Company’s significant accounting policies and other disclosures.

On ~~January 4,~~March 1, 2021, Apache Corporation, ~~announced plans to implement~~the Company’s predecessor registrant, consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which ~~was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization,~~ Apache Corporation became a direct, ~~wholly-owned~~wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares ~~were~~ automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company 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.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, ~~2021,~~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 ~~Apache Corporation’s~~the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021. The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year ~~presentation.~~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 accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.~~

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

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. Additionally, prior to the BCP Business Combination defined below, third-party investors ~~own~~owned a minority interest of approximately 21 percent of Altus Midstream Company ~~(ALTM)~~(ALTM or Altus), which iswas reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM ~~qualifies~~qualified as a variable interest entity under GAAP, ~~for~~ which APA ~~consolidates~~consolidated because a ~~wholly-owned~~wholly owned subsidiary of APA ~~has~~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’s proportionate share of~~Company elected the ~~results of operations generated by the~~fair value option to account for its equity method ~~interests are recorded as a component of “Other, net” under “Revenues and Other”~~interest in ~~the Company’s statement of consolidated operations.~~Kinetik. Refer to Note 6—Equity Method Interests for further detail.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities ~~require~~requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities ~~as of~~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 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), the estimate of income taxes (refer to Note 10—Income Taxes), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. ~~The Company determines fair value measurements in accordance with~~ Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), ~~which~~ provides a hierarchy that prioritizes and defines the types of inputs used to ~~base~~measure fair ~~value measurements.~~value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

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.

Fair value measurements are recorded on a nonrecurring basis when certain qualitative assessments of the Company’s assets indicate potential impairment. Asset impairments recorded in connection with fair value assessments were as follows:

For the Quarter Ended
June 30,
For the Six Months Ended
June 30,
2021 2020 2021 2020
(In millions)
Oil and gas proved property $ 0 $ 20 $ 0 $ 4,319
Gathering, processing, and transmission facilities 0 0 0 68
Goodwill 0 0 0 87
Inventory and other 0 0 0 18
Total Impairments $ 0 $ 20 $ 0 $ 4,492

~~The Company recorded 0 asset impairments in connection with fair value assessments during the first six months of 2021.~~

During the ~~second quarter of 2020,~~three and six months ended June 30, 2022 and 2021, the Company recorded no asset impairments ~~totaling $20 million~~ in connection with fair value ~~assessments on proved property in Egypt. These properties were impaired to their estimated fair values as a result of~~assessments.

Revenue Recognition

There have been no significant changes to ~~planned development activity.~~the Company’s contracts with customers during the six months ended June 30, 2022 and 2021.

~~During~~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 ~~first quarter of 2020, the Company recorded asset impairments totaling $4.5 billion in connection~~product or service has been rendered. Receivables from contracts with fair value assessments. Given the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed itscustomers, including receivables for purchased oil and gas ~~property~~sales and ~~gathering, processing,~~net of allowance for credit losses, were $1.8 billion and ~~transmission (GPT) facilities for impairment based on the net book value of its assets~~$1.3 billion as of ~~March~~June 30, 2022 and December 31, ~~2020. The Company recognized proved property impairments totaling $3.9 billion, $354 million,~~2021, respectively.

Oil and ~~$7 million~~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 ~~U.S., Egypt,~~Company’s statement of consolidated operations.

Refer to Note 14—Business Segment Information for a disaggregation of oil, gas, and ~~North Sea, respectively,~~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 ~~reduce~~each performance obligation as the ~~carrying value~~terms of ~~its oil and gas properties~~payment relate specifically to the ~~estimated fair values as a result of lower forecasted commodity prices, changes~~Company’s efforts to planned development activity, and increasing market uncertainty. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

~~During the first quarter of 2020,~~satisfy its obligations. As such, the Company ~~also recognized impairments of $13 million for~~has elected the ~~early termination of drilling rig leases and $5 million for inventory revaluations, both in~~practical expedients available under the ~~U.S.~~

~~During~~standard to not disclose the ~~first quarter of 2020, the Company performed an interim impairment analysis~~aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the goodwill related to its Egypt reporting segment. Reductions in the estimated net present value of expected future cash flows from oil and gas properties resulted in fair values below the carrying valuesend of the ~~Company’s Egypt~~ reporting ~~unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.~~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.

The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in the first and second quarters of 2020.

~~The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:~~

For the Quarter Ended
June 30,
For the Six Months Ended
June 30,
2021 2020 2021 2020
(In millions)
Proved Properties:
U.S. $ 0 $ 0 $ 0 $ 3,938
Egypt 0 20 0 374
North Sea 0 0 0 7
Total proved properties $ 0 $ 20 $ 0 $ 4,319
Unproved Properties:
U.S. $ 1 $ 29 $ 17 $ 46
Egypt 2 2 4 4
Total unproved properties $ 3 $ 31 $ 21 $ 50

~~Proved properties impaired during the first and second quarters of 2020 had aggregate fair values of $1.9 billion and $32 million, respectively.~~

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

Gathering, Processing, and Transmission (GPT) Facilities

GPT facilities totaled $668 million and $670 million as of June 30, 2021 and December 31, 2020, respectively, with accumulated depreciation for these assets totaling $358 million and $323 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

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

2. ACQUISITIONS AND DIVESTITURES

2022 Activity

In July 2022, the Company completed the acquisition of oil and gas assets in the Delaware Basin for a purchase price of $505 million. The transaction closed on July 29, 2022 for a total cost of $555 million, after including post-effective date adjustments to date. The acquisition was effective April 1, 2022, and was funded primarily from borrowings on the Company’s revolving credit facility. A deposit of $51 million was paid during the second quarter in association with this transaction.

During the second quarter of 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $26 million. During the second quarter of 2022, the Company also completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $7 million, recognizing a gain of approximately $1 million upon closing of these transactions.

During the first quarter of 2022, the Company completed a previously announced transaction to sell certain non-core mineral rights in the Delaware Basin. The Company ~~assessed its long-lived infrastructure~~received total cash proceeds of approximately $736 million after certain post-closing adjustments and recognized an associated gain of approximately $563 million. The Company also completed the sale of other non-core assets and leasehold in multiple transactions for ~~impairment at March 31, 2020, and recorded an impairment~~total cash proceeds of ~~$68~~$8 million. The Company recognized a gain of approximately $1 million ~~on its GPT facilities in Egypt~~upon closing of these transactions during the first quarter of ~~2020.~~ 2022.

The ~~fair values~~BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the ~~impaired assets,~~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 ~~were determined~~are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to ~~be $46 million, were estimated using~~hold their existing shares of Common Stock. As a result of the ~~income approach,~~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 ~~considers internal estimates based on future throughput volumes from applicable development concessions in Egypt~~owned approximately 79 percent of the issued and ~~estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation~~outstanding shares of ALTM Common Stock prior to the ~~oil~~BCP Business Combination, owned approximately 20 percent of the issued and ~~gas proved property impairment assessment, as discussed above, to develop future cash flow projections~~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 ~~were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost~~reflects the difference of ~~capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in~~the Company’s share of ALTM’s deconsolidated balance sheet and the fair value ~~hierarchy.~~

~~Revenue Recognition~~

~~There have been no significant changes to~~of its approximate 20 percent retained ownership in the ~~Company’s contracts with customers during the six months ended June 30, 2021 and 2020.~~

~~Payments under all contracts with customers are typically due and received within a short-term period~~combined entity. A summary of ~~one year or less after physical delivery~~components of the ~~product or service has been rendered. Receivables from contracts with customers, net~~gain, including the ALTM balance sheet amounts deconsolidated at the time of ~~allowance~~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 4000000 of its shares in Kinetik for ~~credit losses, were $993~~cash proceeds of $224 million and ~~$670~~recognized a loss of $25 million, ~~as of June 30, 2021 and December 31, 2020, respectively.~~including transaction fees. Refer to Note ~~14—Business Segment Information~~6—Equity Method Interests for further detail. In connection with this secondary offering, the Company has agreed that within the next 24 months, it will invest a ~~disaggregation~~minimum of ~~oil,~~$100 million of these proceeds for new well drilling and completion activity at the Alpine High play in the Delaware Basin, where Kinetik has exclusive gas and ~~natural gas production revenue by product~~NGL gathering and ~~reporting segment.~~processing rights.

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.

~~The following table presents the Company’s revenues generated from contracts with customers and non-customers:~~

For the Quarter Ended
June 30,
For the Six Months Ended
June 30,
2021 2020 2021 2020
(In millions)
Production revenues from customers $ 1,407 $ 715 $ 2,732 $ 1,903
Production revenues from non-customers 107 (18) 213 30
Total production revenues $ 1,514 $ 697 $ 2,945 $ 1,933

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

~~Transaction, Reorganization, and Separation (TRS)~~

In recent years, the Company streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. In light of the continued streamlining of the Company’s asset portfolio through divestitures and strategic transactions, in late 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations. Efforts related to this reorganization were substantially completed during 2020. The Company incurred and paid a cumulative total of $79 million of reorganization costs through December 31, 2020. An additional $4 million of reorganization costs were incurred in the second quarter and first six months of 2021, primarily related to ongoing consulting and separation activities in the Company’s international operations.

The Company recorded $10 million and $37 million of TRS costs during the second quarter and first six months of 2020, respectively. TRS costs incurred in the first six months of 2020 comprised $34 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs.

~~2. ACQUISITIONS AND DIVESTITURES~~

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 $178 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $65 million in connection with the sale.

During the first quarter of 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $2 million. The Company also completed the sale of certain non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $3 million. The Company recognized a gain of approximately $2 million upon closing of these transactions during the first quarter of 2021.

~~2020 Activity~~

During the second quarter and first six months of 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $2 million and $3 million, respectively.

During the first six months of 2020, the Company completed the sale of certain non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $47 million. The Company recognized a gain of approximately $6 million upon closing of these transactions.

~~Suriname Joint Venture Agreement~~

In December 2019, the Company entered into a joint venture agreement with TotalEnergies (formerly Total S.A.) to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, the Company and TotalEnergies each hold a 50 percent working interest in Block 58. Pursuant to the agreement, the Company operated the drilling of the first four wells, the Maka Central-1, Sapakara West-1, Kwaskwasi-1, and Keskesi East-1, and subsequently transferred operatorship of Block 58 to TotalEnergies on January 1, 2021; however, the Company continued to operate the Keskesi exploration well until completion of drilling operations during the first six months of 2021.

In connection with the agreement, the Company received $100 million from TotalEnergies upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019. All proceeds were applied against the carrying value of the Company’s Suriname properties and associated inventory. The Company recognized a $19 million gain in the first quarter of 2020 associated with the transaction.

Key terms of the agreement provide for Total S.A. to pay a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation. For the first $10 billion of gross capital expenditures, Total S.A. pays 87.5 percent, and the Company pays 12.5 percent; for the next $5 billion in gross expenditures, Total pays 75 percent and the Company pays 25 percent; and for all gross expenditures above $15 billion, Total pays 62.5 percent and the Company pays 37.5 percent. The Company will also receive various other forms of consideration, including a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were ~~$260~~$466 million and ~~$197~~$321 million as of June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively. The increase is primarily attributable to additional drilling activity in Suriname and ~~Egypt, partially offset by dry hole write-offs during the period.~~Egypt.

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

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

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

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of June 30, ~~2021,~~2022, the Company had derivative positions with 1112 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in ~~commodity prices,~~ currency exchange ~~rates, or interest~~ rates.

Derivative Instruments

Commodity Derivative Instruments

As of June 30, ~~2021, the Company had the following open crude oil derivative positions:~~

Fixed-Price Swaps
Production Period Settlement Index Mbbls Weighted Average Fixed Price
July—September 2021 NYMEX WTI 2,024 $60.15
October—December 2021 NYMEX WTI 1,012 $58.59
July—September 2021 Dated Brent 1,656 $63.08
October—December 2021 Dated Brent 828 $61.44

~~As of June 30, 2021, the Company had the following open crude oil financial basis swap contracts:~~

Production Period Settlement Index Mbbls Weighted Average Price Differential
July—September 2021 Midland-WTI/Cushing-WTI 2,024 $0.61
October—December 2021 Midland-WTI/Cushing-WTI 1,012 $0.70

~~As of June 30, 2021,~~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
July—December 2021 NYMEX Henry Hub/IF Waha 23,930 $(0.42) — —
July—December 2021 NYMEX Henry Hub/IF HSC — — 23,930 $(0.07)
January—December 2022 NYMEX Henry Hub/IF Waha 43,800 $(0.45) — —
January—December 2022 NYMEX Henry Hub/IF HSC — — 43,800 $(0.08)
January—December 2023 NYMEX Henry Hub/IF Waha 29,200 $(0.40) — —
January—December 2023 NYMEX Henry Hub/IF HSC — — 29,200 $0.02


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2022	NYMEX Henry Hub/IF Waha	42,320	$(0.70)	—	—
July—December 2022	NYMEX Henry Hub/IF HSC	—	—	42,320	$(0.12)
October—December 2022	NYMEX Henry Hub/IF Waha	920	$(1.19)	—	—
October—December 2022	NYMEX Henry Hub/IF HSC	—	—	920	$(0.19)
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	3,640	$(1.25)	—	—
January—June 2024	NYMEX Henry Hub/IF HSC	—	—	3,640	$(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

~~During the second quarter of 2019,~~The Altus ~~Midstream LP, a subsidiary of ALTM, issued and sold Series A Cumulative redeemable~~ Preferred Units ~~(Preferred Units). Certain redemption features~~ embedded ~~within~~derivative was deconsolidated as of March 31, 2022 as part of the ~~Preferred Units require bifurcation~~BCP Business Combination. Refer to Note 2 —Acquisitions and ~~measurement at fair value. For further~~Divestitures for discussion of ~~this derivative, refer to “Fair Value Measurements” below~~the BCP Business Combination and Note 1 2 —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 ~~separate~~ agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements ~~are~~were arrangements under which the Company ~~has the potential to receive~~received payments calculated based on pricing differentials between Houston Ship Channel and Waha during the calendar years 2020 and 2021. ~~These features require~~This feature required bifurcation and measurement of the change in market ~~values for each period.~~value throughout 2020 and 2021. Unrealized gains orand losses in the fair value of ~~these features are~~this feature were recorded as “Derivative instrument ~~losses,~~gains (losses), net” under “Revenues and Other” in the statement of consolidated ~~operations. Any proceeds received~~operations, and the balance at the end of December 31, 2021 will be ~~deferred and reflected in~~amortized into income over the original tenure of the ~~transportation agreement.~~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													Fair Value Measurements Using
		Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount			Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
		(In millions)
June 30, 2021
															(In millions)
June 30, 2022														June 30, 2022
Assets:	Assets:													Assets:
Commodity derivative instruments	Commodity derivative instruments	$	0	$	2	$	0	$	2	$	0	$	2	Commodity derivative instruments	$	—	$	—	$	—	$	—	$	1	$	1
Liabilities:	Liabilities:													Liabilities:
Commodity derivative instruments	Commodity derivative instruments	0		64		0		64		0		64		Commodity derivative instruments	—		54		—		54		1		55
Pipeline capacity embedded derivatives		0		50		0		50		0		50
Preferred Units embedded derivative		0		0		125		125		0		125
Foreign currency derivative instruments														Foreign currency derivative instruments	—		7		—		7		—		7

December 31, 2020
Assets:

December 31, 2021														December 31, 2021

Liabilities:														Liabilities:
Commodity derivative instruments	Commodity derivative instruments	$	0	$	11	$	0	$	11	$	0	$	11	Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Liabilities:
Pipeline capacity embedded derivative	Pipeline capacity embedded derivative	0		53		0		53		0		53		Pipeline capacity embedded derivative	—		46		—		46		—		46
Preferred Units embedded derivative	Preferred Units embedded derivative	0		0		139		139		0		139		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.

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

The fair value of the Preferred Units embedded derivative is calculated using an income approach, a Level 3 fair value measurement, and determination is based on a range of factors, including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the June 30, 2021 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative:

~~Quantitative Information About Level 3 Fair Value Measurements~~

~~Fair Value as of June 30, 2021~~

~~Valuation Technique~~

~~Significant Unobservable Inputs~~

~~Range/Value~~

~~(In millions)~~

~~Preferred Units embedded derivative~~

~~125~~

~~Option Model~~

Altus’ Imputed
Interest Rate

~~5.62-11.50%~~

Interest Rate
Volatility

~~38.33%~~

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of June 30, 2021, while a one percent decrease would lead to a similar decrease in value as of June 30, 2021. The assumed expected timing until exercise of the exchange option as of June 30, 2021 was 4.95 years.

Derivative Activity Recorded in the Consolidated Balance Sheet

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


							June 30, 2022		December 31, 2021
		June 30, 2021		December 31, 2020
		(In millions)					(In millions)
Current Assets: Other current assets	Current Assets: Other current assets	$	2	$	6	Current Assets: Other current assets	$	—	$	—
Other Assets: Deferred charges and other	Other Assets: Deferred charges and other	0		5		Other Assets: Deferred charges and other	1		—
Total derivative assets	Total derivative assets	$	2	$	11	Total derivative assets	$	1	$	—

Current Liabilities: Other current liabilities	Current Liabilities: Other current liabilities	$	58	$	0	Current Liabilities: Other current liabilities	$	41	$	4
Deferred Credits and Other Noncurrent Liabilities: Other	Deferred Credits and Other Noncurrent Liabilities: Other	181		192		Deferred Credits and Other Noncurrent Liabilities: Other	21		109
Total derivative liabilities	Total derivative liabilities	$	239	$	192	Total derivative liabilities	$	62	$	113

1514

Derivative Activity Recorded in the Statement of Consolidated Operations

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


											For the Quarter Ended June 30,				For the Six Months Ended June 30,
		For the Quarter Ended June 30,				For the Six Months Ended June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions)									(In millions)
Realized:	Realized:									Realized:
Commodity derivative instruments	Commodity derivative instruments	$	(48)	$	(36)	$	100	$	(36)	Commodity derivative instruments	$	(4)	$	(48)	$	(9)	$	100
Foreign currency derivative instruments	Foreign currency derivative instruments	0		(1)		0		(1)		Foreign currency derivative instruments	(2)		—		(2)		—
Realized gain (loss), net	Realized gain (loss), net	(48)		(37)		100		(37)		Realized gain (loss), net	(6)		(48)		(11)		100
Unrealized:	Unrealized:									Unrealized:
Commodity derivative instruments	Commodity derivative instruments	(98)		(111)		(72)		(94)		Commodity derivative instruments	(20)		(98)		(44)		(72)
Pipeline capacity embedded derivatives	Pipeline capacity embedded derivatives	2		(17)		3		(70)		Pipeline capacity embedded derivatives	—		2		—		3
Foreign currency derivative instruments	Foreign currency derivative instruments	0		1		0		(4)		Foreign currency derivative instruments	(6)		—		(8)		—
Preferred units embedded derivative		31		(11)		14		(73)
Preferred Units embedded derivative										Preferred Units embedded derivative	—		31		(31)		14
Unrealized loss, net	Unrealized loss, net	(65)		(138)		(55)		(241)		Unrealized loss, net	(26)		(65)		(83)		(55)
Derivative instrument gains (losses), net	Derivative instrument gains (losses), net	$	(113)	$	(175)	$	45	$	(278)	Derivative instrument gains (losses), net	$	(32)	$	(113)	$	(94)	$	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.”

~~As part of the Company’s ordinary course of business, the~~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.~~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:


							June 30, 2022		December 31, 2021
		June 30, 2021		December 31, 2020
		(In millions)					(In millions)
Inventories	Inventories	$	479	$	492	Inventories	$	473	$	473
Drilling advances	Drilling advances	74		113		Drilling advances	57		55

Prepaid assets and other	Prepaid assets and other	75		71		Prepaid assets and other	27		56
Current decommissioning security for sold Gulf of Mexico assets						Current decommissioning security for sold Gulf of Mexico assets	350		100
Total Other current assets	Total Other current assets	$	628	$	676	Total Other current assets	$	907	$	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 4000000 of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and other” in the Company’s statement of consolidated operations. Refer to Note 2–Acquisitions and Divestitures for further detail. A fair value adjustment gain of $24 million was recorded during the first quarter of 2022 based on the Company’s remaining 8.9 million shares of Kinetik Class A Common Stock as of March 31, 2022.

During the second quarter of 2022, Kinetik issued a 2-for-one split of its Common Stock. Also during the second quarter, the Company received approximately 0.4 million shares of Kinetik’s Class A Common Stock as a paid-in-kind dividend. A fair value adjustment gain of $29 million was recorded during the second quarter based on the Company’s ownership of 18.1 million shares of Kinetik Class A Common Stock on June 30, 2022.

The Company’s ownership represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock, as of March 31, 2022 and June 30, 2022.

The following table presents the activity in the Company’s equity method interest in Kinetik for the six months ended June 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		13
Fair value adjustments		53
Balance at June 30, 2022		$	618

During the three and six months ending June 30, 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the transaction totaling $26 million and $36 million, respectively. As of June 30, ~~2021 and December 31, 2020,~~2022, the Company has recorded accrued GPT costs payable to Kinetik of approximately $8 million.

Prior to the deconsolidation of Altus on February 22, 2022, the Company, through its ownership of Altus, had the following equity method interests in 4 Permian Basin long-haul pipeline entities, which ~~are~~were accounted for under the equity method of ~~accounting.~~accounting at December 31, 2021. For each of the equity method interests, Altus ~~has~~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
June 30,
2021
December 31,
2020
(In millions)
Gulf Coast Express Pipeline, LLC 16.0% $ 278 $ 284
EPIC Crude Holdings, LP 15.0% 167 176
Permian Highway Pipeline, LLC 26.7% 635 615
Shin Oak Pipeline (Breviloba, LLC) 33.0% 474 480
Total Altus equity method interests $ 1,554 $ 1,555

As of June 30, 2021 and December 31, 2020, unamortized basis differences included in the equity method interest balances were $37 million and $38 million, respectively. These amounts represent differences in Altus’ contributions to date and Altus’ underlying equity in the separate net assets within the financial statements of the respective entities. Unamortized basis differences will be amortized into net income over the useful lives of the underlying pipeline assets.


	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 six months ended June 30, ~~2021:~~2022:

Gulf Coast Express
Pipeline LLC EPIC Crude
Holdings, LP Permian Highway
Pipeline LLC Breviloba, LLC Total
(In millions)
Balance at December 31, 2020 $ 284 $ 176 $ 615 $ 480 $ 1,555
Capital contributions 0 1 23 0 24
Distributions (25) 0 (30) (21) (76)
Equity income (loss), net 19 (11) 27 15 50
Accumulated other comprehensive income 0 1 0 0 1
Balance at June 30, 2021 $ 278 $ 167 $ 635 $ 474 $ 1,554

~~Summarized Combined Financial Information~~

~~The following table presents summarized selected income statement data for Altus’ equity method interests (on a 100 percent basis):~~

For the Six Months Ended
June 30,
2021 2020
(In millions)
Operating revenues $ 531 $ 351
Operating income 247 182
Net income 204 147
Other comprehensive income (loss) 4 (5)


	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 June 30, 2022	$	—	$	—	$	—	$	—	$	—

7. OTHER CURRENT LIABILITIES

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


							June 30, 2022		December 31, 2021
		June 30, 2021		December 31, 2020
		(In millions)					(In millions)
Accrued operating expenses	Accrued operating expenses	$	116	$	91	Accrued operating expenses	$	145	$	129
Accrued exploration and development	Accrued exploration and development	166		167		Accrued exploration and development	303		207
Accrued compensation and benefits	Accrued compensation and benefits	147		170		Accrued compensation and benefits	281		292
Accrued interest	Accrued interest	125		140		Accrued interest	96		107
Accrued income taxes	Accrued income taxes	68		25		Accrued income taxes	180		28
Current asset retirement obligation	Current asset retirement obligation	56		56		Current asset retirement obligation	40		41
Current operating lease liability	Current operating lease liability	102		116		Current operating lease liability	121		99
Current portion of derivatives at fair value	Current portion of derivatives at fair value	58		0		Current portion of derivatives at fair value	41		4
Current decommissioning contingency for sold Gulf of Mexico properties						Current decommissioning contingency for sold Gulf of Mexico properties	350		100
Other	Other	117		97		Other	206		164
Total Other current liabilities	Total Other current liabilities	$	955	$	862	Total Other current liabilities	$	1,763	$	1,171

8. ASSET RETIREMENT OBLIGATION

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


	June 30, ~~2021~~2022
	(In millions)
Asset retirement obligation, December 31, ~~2020~~2021	$	~~1,944~~2,130
Liabilities incurred	32
Liabilities settled	~~(10)~~(16)
Liabilities divested	~~(44)~~(4)

Deconsolidation of Altus	(69)
Accretion expense	5658

Asset retirement obligation, June 30, ~~2021~~2022	~~1,949~~2,101
Less current portion	~~(56)~~(40)
Asset retirement obligation, long-term	$	~~1,893~~2,061

9. DEBT AND FINANCING COSTS

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


							June 30, 2022		December 31, 2021
		June 30, 2021		December 31, 2020
		(In millions)					(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	8,030	$	8,052	Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	5,032	$	6,344
Altus credit facility(2)	Altus credit facility(2)	657		624		Altus credit facility(2)	—		657
Apache credit facility(2)		0		150
Syndicated credit facilities(2)						Syndicated credit facilities(2)	275		542
Apache finance lease obligations	Apache finance lease obligations	36		38		Apache finance lease obligations	35		36
Unamortized discount	Unamortized discount	(34)		(35)		Unamortized discount	(28)		(30)
Debt issuance costs	Debt issuance costs	(54)		(57)		Debt issuance costs	(29)		(39)
Total debt	Total debt	8,635		8,772		Total debt	5,285		7,510
Current maturities	Current maturities	(215)		(2)		Current maturities	(125)		(215)
Long-term debt	Long-term debt	$	8,420	$	8,770	Long-term debt	$	5,160	$	7,295

(1) The fair values of the Apache notes and debentures were ~~$8.5~~$4.4 billion and $7.1 billion as of June 30, ~~2021~~2022 and December 31, ~~2020.~~ 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 June 30, 2022, current debt included $123 million carrying value of 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 ~~net of discount,~~carrying value of 3.25% senior notes due April 15, 2022 and $2 million of finance lease obligations. ~~As of December 31, 2020, current debt included $2 million of finance lease obligations.~~

During the ~~six months~~quarter ended ~~June 30, 2021,~~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 ~~$22~~$15 million for an aggregate purchase price of ~~$20~~$16 million in cash, including accrued interest and broker fees, reflecting a ~~discount~~premium to par of ~~an aggregate $2~~$1 million. The Company recognized a $1 million ~~net gain~~loss on ~~extinguishment~~these repurchases.

During the quarter ended March 31, 2022, Apache redeemed the outstanding $213 million principal amount of ~~debt as part~~3.25% senior notes due April 15, 2022, at a redemption price equal to 100% of ~~these transactions.~~their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s revolving credit facility.

~~In March 2018, Apache~~On April 29, 2022, the Company entered into a2 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 ~~totaling $4.0 billion. In March 2019, the term~~ of ~~this facility was extended by one year~~US$1.8 billion (including a letter of credit subfacility of up to ~~March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise~~US$750 million, of ~~an extension option. Apache can~~which US$150 million currently is committed). The Company may increase commitments up to ~~$5.0~~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 2, 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, ~~includes~~with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s 2, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a ~~letter~~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 ~~subfacility of~~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 ~~$3.0 billion,~~an aggregate principal amount of ~~which $2.08 billion was committed as~~US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of ~~June 30, 2021. The facility~~indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is ~~for general corporate purposes.~~ less than US$1.0 billion.

As of June 30, 2022, there were $275 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 0$542 million of borrowings and an aggregate ~~£561~~£748 million and $20 million in letters of credit outstanding under ~~this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility.~~the Former Facility. The ~~outstanding~~ letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

There were 0 borrowings outstanding under Apache’s commercial paper program as of June 30, 2021 and December 31, 2020. Apache did not use its commercial paper program during 2021 and terminated the program.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, there were 0no outstanding borrowings ~~and £34~~under these facilities. As of June 30, 2022, there were £117 million and $17 million in letters of credit outstanding under these facilities.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s 2, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, ~~2020,~~2021, there were ~~$624~~£117 million ~~of borrowings~~ and 0$17 million in letters of credit outstanding under ~~this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache, APA Corporation, or any of its subsidiaries.~~these facilities.

Financing Costs, Net

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


											For the Quarter Ended June 30,				For the Six Months Ended June 30,
		For the Quarter Ended June 30,				For the Six Months Ended June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions)									(In millions)
Interest expense	Interest expense	$	110	$	107	$	222	$	214	Interest expense	$	79	$	110	$	169	$	222
Amortization of debt issuance costs	Amortization of debt issuance costs	3		2		5		4		Amortization of debt issuance costs	5		3		7		5
Capitalized interest	Capitalized interest	(2)		(2)		(4)		(6)		Capitalized interest	(5)		(2)		(8)		(4)
Gain on extinguishment of debt		(1)		(140)		(1)		(140)
(Gain) loss on extinguishment of debt										(Gain) loss on extinguishment of debt	—		(1)		67		(1)
Interest income	Interest income	(3)		(1)		(5)		(3)		Interest income	(3)		(3)		(7)		(5)
Financing costs, net	Financing costs, net	$	107	$	(34)	$	217	$	69	Financing costs, net	$	76	$	107	$	228	$	217

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 second quarter of 2022, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the second quarter and the first six months of 2021, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. ~~During~~

On May 26, 2022, the ~~second quarter~~U.K. Chancellor announced a new tax on the profits of 2020, the Company’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas ~~asset impairments, a goodwill impairment, and an increase~~companies operating in the ~~amount~~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 tax rate and will be effective for the period of ~~valuation allowance against its~~May 26, 2022, through December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation will be recorded in the period of enactment. Therefore, in the third quarter of 2022, the Company expects to record a deferred tax ~~assets.~~expense of approximately $230 million to $250 million related to the remeasurement of the June 30, 2022 U.K. deferred tax liability.

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.~~controls, which also may include controls related to the potential impacts of climate change. As of June 30, ~~2021,~~2022, the Company has an accrued liability of approximately ~~$71~~$48 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 ~~Apache Corporation’s~~the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021.

Argentine Environmental Claims

On March 12, 2014, the Company and ~~Argentina Tariff~~

~~No material change in~~its subsidiaries completed the ~~status~~sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad ~~Anónima~~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 ~~indemnities matter has occurred since~~(Pioneer) in an amount up to $45 million pursuant to the ~~filing~~terms and conditions of ~~Apache Corporation’s~~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, ~~2020.~~

~~Louisiana Restoration~~

~~As more fully described in Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020,~~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 ~~2021,~~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. ~~Some of the cases have been remanded to state court with the remand orders being appealed.~~ In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and ~~areas~~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 ~~their remaining~~ Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

Canadian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, 4 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 ~~purported~~ 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 3 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 2 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 ~~have been~~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 remand order is being appealed to the 3rd Circuit Court of Appeals. Further activity in the case has been stayed pending this appellate review.

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

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, ~~Inc,~~Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of ~~five~~5 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. ~~The Company~~Further appeal is ~~evaluating appeal.~~pending.

Oklahoma Class ~~Actions~~Action

The Company is a party to 2a purported class ~~actions~~action in Oklahoma styled~~Bigie Lee Rhea v. Apache Corporation, Case No. 6:14-cv-00433-JH, and~~ Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219. ~~The~~

~~Rhea~~ case has been certified and includes a class of royalty owners seeking damages in excess of $250 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case ~~has not been certified and~~ 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 ~~amount~~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 ~~this claim is not yet reasonably determinable. While adverse judgments against the Company are possible, the Company intends to vigorously defend these lawsuits and claims.~~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. ~~On March 4, 2021, another lawsuit, captioned~~ ~~Brian Schwegel v. Apache Corporation, et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging identical allegations.~~ The Company believes that ~~all~~ plaintiffs’ claims lack merit and intends to vigorously defend ~~these lawsuits.~~this lawsuit.

On March 16, 2021, 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 ~~June 7, 2021, another lawsuit, captioned~~ ~~Thomas Miskella, Derivatively~~March 17, 2022, the trial court granted Defendants’ Special Exceptions and ~~on behalf of APA Corporation v. John J. Christmann IV et al., was filed in~~dismissed the ~~United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. On June 25, 2021, another lawsuit, captioned~~ ~~Rawley Brodeen, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. And on July 14, 2021, another lawsuit, captioned~~ ~~Barry Dudenhoeffer, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al.~~, was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. The defendants believe the plaintiffs’ derivative claims lack merit and intend to vigorously defend these lawsuits.claim with prejudice.

Environmental Matters

As of June 30, ~~2021,~~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 ~~responding~~has responded to the information request. The EPA has ~~not commenced~~referred the notice for civil enforcement ~~proceedings, and~~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 ~~responding~~has responded to the information request. The EPA has ~~not commenced~~referred the notice for civil enforcement ~~proceedings, and~~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 June 30, ~~2021~~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 ~~Asset Retirement~~Decommissioning Obligations on Sold Properties

In 2013, ~~the Company~~Apache sold its Gulf of Mexico (GOM) Shelf operations and properties ~~(Legacy~~and its GOM ~~Assets)~~operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, ~~the Company~~Apache received cash consideration of $3.75 billion and Fieldwood assumed ~~$1.5 billion of discounted asset abandonment liabilities as of~~ the ~~disposition date.~~obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment ~~liabilities,~~obligations, Fieldwood posted letters of credit in favor of ~~the Company~~Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a ~~trust account (Trust A),~~beneficiary and which iswere funded by ~~a 10 percent~~2 net profits ~~interest~~interests (NPIs) depending on future oil ~~prices and of which the Company is the beneficiary.~~prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which ~~the Company~~Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of ~~Credit.~~Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, ~~the Company~~Apache holds ~~two~~2 bonds (Bonds) and ~~the remaining~~5 Letters of Credit to secure Fieldwood’s asset retirement obligations ~~(AROs)~~ on the Legacy GOM Assets as and when ~~such abandonment and decommissioning obligations are~~Apache is required to ~~be performed~~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. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Legacy GOM Assets into a standalone company, and proceeds of production of the Legacy GOM Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then the Company expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, the Company has agreed to provide a standby loan of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.

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 June 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 June 30, 2022, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $825 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 $733 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, $383 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

~~The~~Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units ~~are~~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 ~~applies~~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 ~~may be~~was recorded, if applicable. The amount of such adjustment iswas determined based upon the accreted value method to reflect the passage of time until the Preferred Units ~~are~~were exchangeable at the option of the holder. Pursuant to this method, the net transaction price iswas accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment iswas limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end iswas equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price.

Activity related to the Preferred Units is as follows:


		Units Outstanding	Financial Position(1)			Units Outstanding	Financial Position
		(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019		638,163	$	555
Distribution of in-kind additional Preferred Units		22,531	0
Cash distributions to Altus Preferred Unit limited partners		—	(23)
Allocation of Altus Midstream LP net income		N/A	76
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020		660,694	608
						(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units at: December 31, 2020					Redeemable noncontrolling interest — Preferred Units at: December 31, 2020	660,694	$	608
Cash distributions to Altus Preferred Unit limited partners	Cash distributions to Altus Preferred Unit limited partners	—	(23)		Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	Distributions payable to Altus Preferred Unit limited partners	—	(11)		Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	Allocation of Altus Midstream LP net income	N/A	39		Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment					Accreted value adjustment	N/A	82
Redeemable noncontrolling interest — Preferred Units at: December 31, 2021					Redeemable noncontrolling interest — Preferred Units at: December 31, 2021	660,694	712

Allocation of Altus Midstream LP net income					Allocation of Altus Midstream LP net income	N/A	12
Accreted value adjustment(1)	Accreted value adjustment(1)	N/A	4		Accreted value adjustment(1)	N/A	(82)
Redeemable noncontrolling interest — Preferred Unit at: June 30, 2021		660,694	617
Redeemable noncontrolling interest — Preferred Units at: February 22, 2022					Redeemable noncontrolling interest — Preferred Units at: February 22, 2022	660,694	642
Preferred Units embedded derivative	Preferred Units embedded derivative		125		Preferred Units embedded derivative		89
Deconsolidation of Altus					Deconsolidation of Altus		(731)
			$	742			$	—

(1) ~~The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as~~Includes the reversal of ~~June 30, 2021 is calculated as~~previously recorded accreted value adjustments of $53 million due to the ~~greater~~deconsolidation of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of June 30, 2021, the Redemption Price would have been based on a 1.3 times multiple of invested capital, which was $813 million, less certain cash distributions. This was greater than using an 11.5 percent internal rate of return, which would equate to a redemption value of $721 million.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 1-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization.

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

Net Income ~~(Loss)~~ per Common Share

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


													For the Quarter Ended June 30,
		For the Quarter Ended June 30,											2022					2021
		2021					2020						Income		Shares	Per Share		Income		Shares	Per Share
		Income		Shares	Per Share		Loss		Shares	Per Share
		(In millions, except per share amounts)											(In millions, except per share amounts)
Basic:	Basic:											Basic:
Income (loss) attributable to common stock		$	316	378	$	0.83	$	(386)	378	$	(1.02)
Income attributable to common stock												Income attributable to common stock	$	926	341	$	2.72	$	316	378	$	0.83
Effect of Dilutive Securities:	Effect of Dilutive Securities:											Effect of Dilutive Securities:
Stock options and other	Stock options and other	$	0	1	$	0	$	0	0	$	0	Stock options and other	$	—	1	$	(0.01)	$	—	1	$	—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	(6)	—	$	(0.01)	$	—	—	$	—	Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	—	—	$	—	$	(6)	—	$	(0.01)
Diluted:	Diluted:											Diluted:
Income (loss) attributable to common stock		$	310	379	$	0.82	$	(386)	378	$	(1.02)
Income attributable to common stock												Income attributable to common stock	$	926	342	$	2.71	$	310	379	$	0.82

		For the Six Months Ended June 30,											For the Six Months Ended June 30,
		2021					2020						2022					2021
		Income		Shares	Per Share		Loss		Shares	Per Share			Income		Shares	Per Share		Income		Shares	Per Share
		(In millions, except per share amounts)											(In millions, except per share amounts)
Basic:	Basic:											Basic:
Income (loss) attributable to common stock		$	704	378	$	1.86	$	(4,866)	378	$	(12.88)
Income attributable to common stock												Income attributable to common stock	$	2,809	344	$	8.18	$	704	378	$	1.86
Effect of Dilutive Securities:	Effect of Dilutive Securities:											Effect of Dilutive Securities:
Stock options and other	Stock options and other	$	0	1	$	0	$	0	0	$	0	Stock options and other	$	—	—	$	(0.03)	$	—	1	$	—

Diluted:	Diluted:											Diluted:
Income (loss) attributable to common stock		$	704	379	$	1.86	$	(4,866)	378	$	(12.88)
Income attributable to common stock												Income attributable to common stock	$	2,809	344	$	8.15	$	704	379	$	1.86

~~The~~

Prior to the deconsolidation of Altus on February 22, 2022, the Company ~~uses~~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 June 30, 2020 and for each of the~~ six months ended June 30, ~~2021 and 2020.~~2021. The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of ~~3.4~~2.0 million and ~~5.2~~3.4 million during the second quarters of ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~3.7~~2.7 million and ~~5.4~~3.7 million during the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively.

Stock Repurchase Program

~~In 2013 and 2014, the Company’s~~During 2018, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common ~~stock, and during~~stock. No shares were purchased under this authorization through December 31, 2020. During the fourth quarter of ~~2018,~~2021, the Company’s Board of Directors authorized the purchase of ~~up to~~an additional 40 million ~~additional~~ shares of the Company’s common stock. Shares may be purchased either in the open market or through privately ~~held~~ negotiated transactions. ~~The~~

In the second quarter of 2022, the Company ~~initiated the buyback program on June 10, 2013, and, through June 30, 2021, has~~ repurchased ~~a total of 40~~7.0 million shares at an average price of ~~$79.18~~$41.60 per ~~share.~~share, and as of June 30, 2022, the Company had remaining authorization to repurchase up to 34.6 million shares. For the six months ended June 30, 2022, the Company repurchased 14.2 million shares at an average price of $38.79 per share The Company is not obligated to acquire any ~~specific number of shares and~~additional shares. The Company did ~~0t purchase~~not repurchase any shares during the six months ended June 30, 2021.

The Company repurchased 6.9 million shares at an average price of $33.88 per share in July 2022, and as of July 31, 2022, the Company had remaining authorization to repurchase up to 27.7 million shares. The Company is not obligated to acquire any additional shares.

Common Stock Dividends

For the ~~quarter~~quarters ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company paid $9$43 million and ~~$10~~$9 million, respectively, in dividends on its common stock. For the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, the Company paid ~~$19~~$86 million and ~~$104~~$19 million, respectively, in dividends on its common stock. In

During the ~~first~~third quarter of ~~2020,~~2021, the Company’s Board of Directors approved ~~a reduction~~an increase in its quarterly dividend from $0.025 per share to $0.0625 per share and, in the ~~Company’s quarterly dividend~~fourth quarter of 2021, approved a further increase to $0.125 per ~~share from $0.25 to $0.025, effective for all dividends payable after March 12, 2020.~~share.

2526

14. BUSINESS SEGMENT INFORMATION

As of June 30, ~~2021,~~2022, the Company is engaged in exploration and production (Upstream) activities across 3 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. ~~The~~Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business iswas operated by Altus Midstream Company, which ~~owns, develops,~~owned, developed, and ~~operates~~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 North Sea U.S. Altus Midstream Intersegment Eliminations & Other
Total(1)
Upstream
For the Quarter Ended June 30, 2021 (In millions)
Revenues:
Oil revenues $ 432 $ 216 $ 493 $ 0 $ 0 $ 1,141
Natural gas revenues 65 27 134 0 0 226
Natural gas liquids revenues 2 4 141 0 0 147
Oil, natural gas, and natural gas liquids production revenues 499 247 768 0 — 1,514
Purchased oil and gas sales 0 0 239 3 0 242
Midstream service affiliate revenues — — — 32 (32) 0
499 247 1,007 35 (32) 1,756
Operating Expenses:
Lease operating expenses 114 98 99 0 0 311
Gathering, processing, and transmission 3 8 74 8 (32) 61
Purchased oil and gas costs 0 0 259 3 0 262
Taxes other than income 0 0 47 4 0 51
Exploration 14 3 2 0 7 26
Depreciation, depletion, and amortization 137 63 148 3 0 351
Asset retirement obligation accretion 0 20 7 1 0 28
268 192 636 19 (25) 1,090
Operating Income (Loss)(2)
$ 231 $ 55 $ 371 $ 16 $ (7) 666
Other Income (Expense):
Derivative instrument gains, net (113)
Gain on divestitures, net 65
Other 74
General and administrative (86)
Transaction, reorganization, and separation (4)
Financing costs, net (107)
Income Before Income Taxes $ 495

Egypt North Sea U.S. Altus Midstream Intersegment Eliminations & Other
Total(1)
Upstream
For the Six Months Ended June 30, 2021 (In millions)
Revenues:
Oil revenues $ 834 $ 457 $ 841 $ 0 $ 0 $ 2,132
Natural gas revenues 135 58 345 0 0 538
Natural gas liquids revenues 4 10 261 0 0 275
Oil, natural gas, and natural gas liquids production revenues 973 525 1,447 0 — 2,945
Purchased oil and gas sales 0 0 676 6 0 682
Midstream service affiliate revenues — — — 64 (64) 0
973 525 2,123 70 (64) 3,627
Operating Expenses:
Lease operating expenses 218 173 185 0 (1) 575
Gathering, processing, and transmission 4 20 143 15 (63) 119
Purchased oil and gas costs 0 0 751 5 0 756
Taxes other than income 0 0 87 8 0 95
Exploration 22 23 18 0 12 75
Depreciation, depletion, and amortization 267 147 273 6 0 693
Asset retirement obligation accretion 0 39 15 2 0 56
511 402 1,472 36 (52) 2,369
Operating Income (Loss)(2)
$ 462 $ 123 $ 651 $ 34 $ (12) 1,258
Other Income (Expense):
Derivative instrument gains, net 45
Gain on divestitures, net 67
Other 135
General and administrative (169)
Transaction, reorganization, and separation (4)
Financing costs, net (217)
Income Before Income Taxes $ 1,115
Total Assets(3)
$ 3,116 $ 2,127 $ 5,964 $ 1,839 $ 466 $ 13,512


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

For the Quarter Ended June 30, 2022	(In millions)
Revenues:
Oil revenues	$	902	$	307	$	654	$	—	$	—	$	1,863
Natural gas revenues	88		64		281		—		—		433
Natural gas liquids revenues	3		12		214		—		—		229
Oil, natural gas, and natural gas liquids production revenues	993		383		1,149		—		—		2,525
Purchased oil and gas sales	—		—		522		—		—		522

	993		383		1,671		—		—		3,047
Operating Expenses:
Lease operating expenses	131		118		110		—		—		359
Gathering, processing, and transmission	5		12		77		—		—		94
Purchased oil and gas costs	—		—		528		—		—		528
Taxes other than income	—		—		78		—		—		78
Exploration	12		2		1		—		41		56
Depreciation, depletion, and amortization	91		54		133		—		—		278
Asset retirement obligation accretion	—		20		9		—		—		29

	239		206		936		—		41		1,422
Operating Income (Loss)(2)	$	754	$	177	$	735	$	—	$	(41)	1,625

Other Income (Expense):
Derivative instrument losses, net											(32)

Loss on divestitures, net											(27)
Other, net											64
General and administrative											(89)
Transaction, reorganization, and separation											(3)
Financing costs, net											(76)
Income Before Income Taxes											$	1,462


		Egypt		North Sea		U.S.		Altus Midstream				Intersegment Eliminations & Other				Total(1)					Egypt(1)			North Sea			U.S.			Altus Midstream		Intersegment Eliminations & Other		Total(4)
		Upstream																Upstream
For the Quarter Ended June 30, 2020		(In millions)

For the Six Months Ended June 30, 2022																		For the Six Months Ended June 30, 2022			(In millions)
Revenues:	Revenues:																	Revenues:
Oil revenues	Oil revenues	$	187	$	128	$	198			$	0			$	0				$	513	Oil revenues		$	1,692		$	635		$		1,253	$	—	$	—	$	3,580
Natural gas revenues	Natural gas revenues	70		7		53		0				0				130		Natural gas revenues			186			163			464			—		—		813
Natural gas liquids revenues	Natural gas liquids revenues	1		3		50		0				0				54		Natural gas liquids revenues			6			28			421			—		(3)		452
Oil, natural gas, and natural gas liquids production revenues	Oil, natural gas, and natural gas liquids production revenues	258		138		301		0				—				697		Oil, natural gas, and natural gas liquids production revenues			1,884			826			2,138			—		(3)		4,845
Purchased oil and gas sales	Purchased oil and gas sales	0		0		54		1				0				55		Purchased oil and gas sales			—			—			866			5		—		871
Midstream service affiliate revenues	Midstream service affiliate revenues	—		—		—		31				(31)				—		Midstream service affiliate revenues			—			—			—			16		(16)		—
		258		138		355		32				(31)				752					1,884			826			3,004			21		(19)		5,716
Operating Expenses:	Operating Expenses:																	Operating Expenses:
Lease operating expenses	Lease operating expenses	98		75		90		0				1				264		Lease operating expenses			262			214			228			—		(1)		703
Gathering, processing, and transmission	Gathering, processing, and transmission	13		11		70		10				(32)				72		Gathering, processing, and transmission			10			24			154			5		(18)		175
Purchased oil and gas costs	Purchased oil and gas costs	0		0		46		0				0				46		Purchased oil and gas costs			—			—			879			—		—		879
Taxes other than income	Taxes other than income	0		0		20		3				0				23		Taxes other than income			—			—			145			3		—		148
Exploration	Exploration	22		15		31		—				4				72		Exploration			27			7			5			—		59		98
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	158		79		178		3				0				418		Depreciation, depletion, and amortization			188			116			263			2		—		569
Asset retirement obligation accretion	Asset retirement obligation accretion	0		18		8		1				0				27		Asset retirement obligation accretion			—			40			17			1		—		58
Impairments		20		0		0		0				0				20

		311		198		443		17				(27)				942					487			401			1,691			11		40		2,630
Operating Income (Loss)(2)	Operating Income (Loss)(2)	$	(53)	$	(60)	$	(88)	$	15			$	(4)			(190)		Operating Income (Loss)(2)			$	1,397		$	425		$	1,313		$	10	$	(59)	3,086

Other Income (Expense):	Other Income (Expense):																	Other Income (Expense):
Derivative instrument losses, net	Derivative instrument losses, net															(175)		Derivative instrument losses, net																(94)

Other																19
Gain on divestitures, net																		Gain on divestitures, net																1,149
Other, net																		Other, net																109
General and administrative	General and administrative															(94)		General and administrative																(245)
Transaction, reorganization, and separation	Transaction, reorganization, and separation															(10)		Transaction, reorganization, and separation																(17)
Financing costs, net	Financing costs, net															34		Financing costs, net																(228)
Loss Before Income Taxes																$	(416)
Income Before Income Taxes																		Income Before Income Taxes																$	3,760

Total Assets(3)																		Total Assets(3)			$	3,107		$	2,103		$	7,156		$	—	$	558	$	12,924


		Egypt		North Sea		U.S.		Altus Midstream				Intersegment Eliminations & Other				Total(1)					Egypt(1)			North Sea			U.S.			Altus Midstream		Intersegment Eliminations & Other		Total(4)
		Upstream																Upstream
For the Six Months Ended June 30, 2020		(In millions)

For the Quarter Ended June 30, 2021																		For the Quarter Ended June 30, 2021			(In millions)
Revenues:	Revenues:																	Revenues:
Oil revenues	Oil revenues	$	520	$	399	$	626			$	0			$	0				$	1,545	Oil revenues		$	432		$	216		$		493	$	—	$	—	$	1,141
Natural gas revenues	Natural gas revenues	135		26		92		0				0				253		Natural gas revenues			65			27			134			—		—		226
Natural gas liquids revenues	Natural gas liquids revenues	4		10		121		0				0				135		Natural gas liquids revenues			2			4			141			—		—		147
Oil, natural gas, and natural gas liquids production revenues	Oil, natural gas, and natural gas liquids production revenues	659		435		839		0				—				1,933		Oil, natural gas, and natural gas liquids production revenues			499			247			768			—		—		1,514
Purchased oil and gas sales	Purchased oil and gas sales	0		0		162		1				0				163		Purchased oil and gas sales			—			—			239			3		—		242
Midstream service affiliate revenues		—		—		—		72				(72)				0
Midstream service revenues																		Midstream service revenues			—			—			—			32		(32)		—
		659		435		1,001		73				(72)				2,096					499			247			1,007			35		(32)		1,756
Operating Expenses:	Operating Expenses:																	Operating Expenses:
Lease operating expenses	Lease operating expenses	210		156		233		0				0				599		Lease operating expenses			114			98			99			—		—		311
Gathering, processing, and transmission	Gathering, processing, and transmission	23		27		145		20				(72)				143		Gathering, processing, and transmission			3			8			74			8		(32)		61
Purchased oil and gas costs	Purchased oil and gas costs	0		0		131		1				0				132		Purchased oil and gas costs			—			—			259			3		—		262
Taxes other than income	Taxes other than income	0		0		49		7				0				56		Taxes other than income			—			—			47			4		—		51
Exploration	Exploration	40		17		66		0				6				129		Exploration			14			3			2			—		7		26
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	319		188		471		6				0				984		Depreciation, depletion, and amortization			137			63			148			3		—		351
Asset retirement obligation accretion	Asset retirement obligation accretion	0		36		16		2				0				54		Asset retirement obligation accretion			—			20			7			1		—		28
Impairments		529		7		3,956		0				0				4,492

		1,121		431		5,067		36				(66)				6,589					268			192			636			19		(25)		1,090
Operating Income (Loss)(2)	Operating Income (Loss)(2)	$	(462)	$	4	$	(4,066)	$	37			$	(6)			(4,493)		Operating Income (Loss)(2)			$	231		$	55		$	371		$	16	$	(7)	666

Other Income (Expense):	Other Income (Expense):																	Other Income (Expense):
Derivative instrument losses, net	Derivative instrument losses, net															(278)		Derivative instrument losses, net																(113)
Gain on divestitures, net	Gain on divestitures, net															25		Gain on divestitures, net																65
Other, net	Other, net															32		Other, net																74
General and administrative	General and administrative															(162)		General and administrative																(86)
Transaction, reorganization, and separation	Transaction, reorganization, and separation															(37)		Transaction, reorganization, and separation																(4)
Financing costs, net	Financing costs, net															(69)		Financing costs, net																(107)
Loss Before Income Taxes																$	(4,982)
Income Before Income Taxes																		Income Before Income Taxes																$	495

Total Assets(3)		$	3,098	$	2,339	$	5,821	$	1,627			$	114			$	12,999


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

For the Six Months Ended June 30, 2021	(In millions)
Revenues:
Oil revenues	$	834	$	457	$	841	$	—	$	—	$	2,132
Natural gas revenues	135		58		345		—		—		538
Natural gas liquids revenues	4		10		261		—		—		275
Oil, natural gas, and natural gas liquids production revenues	973		525		1,447		—		—		2,945
Purchased oil and gas sales	—		—		676		6		—		682
Midstream service affiliate revenues	—		—		—		64		(64)		—
	973		525		2,123		70		(64)		3,627
Operating Expenses:
Lease operating expenses	218		173		185		—		(1)		575
Gathering, processing, and transmission	4		20		143		15		(63)		119
Purchased oil and gas costs	—		—		751		5		—		756
Taxes other than income	—		—		87		8		—		95
Exploration	22		23		18		—		12		75
Depreciation, depletion, and amortization	267		147		273		6		—		693
Asset retirement obligation accretion	—		39		15		2		—		56

	511		402		1,472		36		(52)		2,369
Operating Income (Loss)(2)	$	462	$	123	$	651	$	34	$	(12)	1,258

Other Income (Expense):
Derivative instrument gains, net											45
Gain on divestitures, net											67
Other, net											135
General and administrative											(169)
Transaction, reorganization, and separation											(4)
Financing costs, net											(217)
Income Before Income Taxes											$	1,115

Total Assets(3)	$	3,116	$	2,127	$	5,964	$	1,839	$	466	$	13,512

(1)Includes ~~noncontrolling interests in Egypt~~revenue from non-customers for the quarters and ~~Altus.~~six months ended June 30, 2022 and 2021 of:


	For the Quarter Ended June 30,				For the Six Months Ended June 30,
	2022		2021		2022		2021

	(In millions)
Oil	$	302	$	97	$	552	$	190
Natural gas	30		10		61		22
Natural gas liquids	1		—		2		1

(2)Operating income of U.S. and Egypt includes leasehold impairments of $1 million and $1 million, respectively, for the second quarter of 2022. Operating income of U.S. and Egypt includes leasehold impairments of $4 million and $2 million, respectively, for the first six months of 2022. Operating income of U.S. and Egypt includes leasehold and other asset impairments of $1 million and $2 million, respectively, for the second quarter of 2021. Operating income of U.S. and Egypt includes leasehold impairments of $17 million and $4 million, respectively, for the first six months of 2021. Operating loss of U.S. and Egypt includes leasehold and other asset impairments of $29 million and $22 million, respectively, for the second quarter of 2020. Operating income (loss) of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $4.0 billion, $533 million, and $7 million, respectively, for the first six months of 2020.

(3)Intercompany balances are excluded from total assets.

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

2930

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

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in ~~Apache Corporation’s~~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 ~~Apache’s~~the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021.

On ~~January 4,~~March 1, 2021, Apache Corporation ~~announced plans to implement~~consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which ~~was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization,~~ Apache Corporation became a direct, ~~wholly-owned~~wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares ~~were~~ automatically converted into equivalent corresponding shares of ~~APA.~~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.

Overview

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

~~The Company’s mission is~~APA believes energy underpins global progress, and the Company aims to ~~grow~~be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. Today, the world faces a dual challenge: To meet growing demand for energy and to do so in ~~an innovative, safe, environmentally responsible,~~a cleaner, more sustainable way. APA believes society can accomplish both and ~~profitable manner~~strives to meet those challenges while creating value for ~~the long-term benefit of~~all its stakeholders. ~~The Company is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.~~

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. ~~Uncertainty~~Uncertainties in the global supply chain, commodity prices, and financial markets, ~~during 2020~~including the impact of inflation and ~~2021~~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 ~~on a priority basis~~ to debt ~~reduction.~~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 second quarter of ~~2021,~~2022, the Company reported net income attributable to common stock of $926 million, or $2.71 per diluted share, compared to net income of $316 million, or $0.82 per diluted ~~common share, compared to a loss of $386 million, or $1.02 per diluted common~~ share, in the second quarter of ~~2020. The increase in net~~2021. Net income compared to the prior-year period is primarily the result of significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic began to negatively affect economic activity and the oil markets. In response to lower commodity prices, the Company materially reduced its upstream capital investment budget and drilling activity during the first half of 2020. Daily production decreased 9 percent from an average of 435 Mboe/d infor the second quarter of ~~2020~~2022 benefited from higher revenues attributable to ~~an average~~a new merged concession agreement in Egypt and higher commodity prices. The increase in realized prices was primarily driven by the effects of ~~395 Mboe/d~~global inflation, the conflict in ~~the second quarter of 2021.~~Ukraine on global commodity prices, and uncertainties around spare capacity and energy security globally.

The Company generated ~~$1.6~~$2.4 billion of cash from operating activities during the first six months of ~~2021,~~2022, a ~~180~~48 percent increase from the first six months of ~~2020~~2021, driven by higher ~~commodity prices~~oil and ~~associated~~gas revenues. Since year-end 2021, the Company has reduced its total outstanding debt and redeemable preferred interests by $2.2 billion and $712 million, respectively, through the deconsolidation of ALTM and the retirement of outstanding notes and debentures. The Company ~~ended~~also repurchased 14.2 million shares of its common stock for $552 million during the ~~quarter with $1.2 billion~~first six months of ~~cash.~~2022. The Company had $282 million of cash on hand at June 30, 2022.

3031

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 third quarter of 2021 from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021 further increased to $0.125 per share.

•Beginning in the fourth quarter of 2021 and through the end of the second quarter of 2022, the Company has repurchased 45.4 million shares of the Company’s common stock. As of June 30, 2022, the Company had remaining authorization to repurchase up to 34.6 million shares under the Company’s share repurchase programs. Additionally, the Company repurchased an additional 6.9 million shares of the Company’s common stock in July of 2022.

The Company does not anticipate any significant changes to the activity levels set forth 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

•~~Equivalent~~Daily boe production from the Company’s U.S. assets accounted for 6152 percent of its total production during the second quarter of ~~2021. After halting all~~2022. The Company’s initial delineation program in its Austin Chalk area had mixed results, prompting a pause in planned drilling and completion ~~activity for most of 2020, in early 2021~~activity.

•During the Company re-activated one rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. The Company was also active in completing its backlog of Permian wells previously drilled but not completed. For the second quarter the Company ~~placed 27 wells online~~entered into a transaction to acquire properties in the ~~Permian~~Texas Delaware Basin ~~including five at Alpine High. Three~~near existing operations, primarily in Loving and Reeves counties. The acquired properties have a combination of producing wells, ~~were drilled~~wells in the ~~Austin Chalk where the results are continuing to be evaluated.~~process of drilling and completion, and an inventory of undrilled locations. The Company ~~is assessing~~expects production will average 12,000 to 14,000 boe/d for the ~~addition~~remaining five months of the year. The purchase price was $505 million, and the transaction closed on July 29 for a ~~third rig in the U.S., which would provide a path~~total cost of $555 million after including post-effective date adjustments to ~~sustained oil production.~~date.

International

•In ~~May 2021,~~Egypt, the Company reached an agreement in principle with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of our production-sharing contracts. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust cost oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases. The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The final draft of this agreement has been completed and is scheduled to move to the Egyptian Parliament and President in the fall for approvals to complete the process.

•~~The Company~~ averaged ~~six~~12 drilling rigs ~~in Egypt~~ and ~~completed 15~~drilled 11 new productive wells during the ~~first half~~second quarter of ~~2021. Second-quarter~~2022. Second quarter 2022 gross equivalent production in the Company’s Egypt assets ~~decreased 17~~increased 1 percent from the second quarter of ~~2020, given reduced drilling activity over~~2021, while net production increased 25 percent, primarily a function of improved cost recovery under the ~~preceding year.~~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. ~~Upon ratification of the new PSC agreement, the~~The Company ~~expects~~continues to ~~further~~ increase drilling and workover ~~activity.~~activity as a result of the merged concession agreement.

•The Company averaged two rigs in the North Sea during the second quarter of ~~2021.~~2022. Production ~~from the Forties field~~ was ~~significantly~~ impacted by ~~compressor~~ downtime ~~extended platform~~from maintenance turnaround ~~work, and third-party pipeline outages~~at Forties during the first half of ~~the year. Further impacts are expected~~2022. North Sea production in the ~~third quarter~~second half of ~~2021~~2022 is expected to benefit from ~~continued operational downtime~~completion of maintenance activities and ~~planned platform maintenance turnarounds~~production commencing on the ~~Beryl platforms.~~Garten-3 development well.

•In late 2020, the Company commenced drilling a fourth exploration well at the Keskesi prospect in Block 58 offshore Suriname. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with ongoing exploration and appraisal activities continuing to progress. During the second quarter of ~~2021, two rigs conducted appraisal work at the Sapakara and Keskesi discoveries.~~

•~~In July 2021,~~2022, the Company announced ~~drilling success at Sapakara South-1, an appraisal~~flow test results from the Krabdagu exploration well ~~located~~ on ~~the eastern edge of the Sapakara area,~~Block 58 offshore Suriname, which encountered approximately 3032 meters of net ~~black oil~~ pay in ~~a single zone~~each of ~~high-quality Campano-Maastrichtian reservoir.~~the Upper Campanian and Lower Campanian zones. Appraisal drilling will be necessary to confirm additional resource and optimal development well locations. The Maersk Valiant drillship ~~will soon mobilize to~~is currently drilling the ~~Bonboni~~Dikkop exploration ~~prospect~~well in the ~~northern~~central portion of the block, after which it is expected to continue exploration and appraisal activities in the central portion of Block ~~58 before returning later in the year to flow test Sapakara South-1.~~58. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding a 50 percent working interest.

•The Company is currently drilling the Baja exploration well on Block 53 offshore Suriname, adjacent to Block 58 operations. APA is the operator and holds a 45 percent interest in Block 53.

3132

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

Revenue

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


																			For the Quarter Ended June 30,								For the Six Months Ended June 30,
		For the Quarter Ended June 30,								For the Six Months Ended June 30,									2022				2021				2022				2021
		2021				2020				2021				2020					$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
		($ in millions)																	($ in millions)
Oil Revenues:	Oil Revenues:																	Oil Revenues:
United States	United States	$	493	43	%	$	198	39	%	$	841	39	%	$	626	41	%	United States	$	654	35	%	$	493	43	%	$	1,253	35	%	$	841	39	%
Egypt(1)	Egypt(1)	432		38	%	187		36	%	834		39	%	520		33	%	Egypt(1)	902		48	%	432		38	%	1,692		47	%	834		39	%
North Sea	North Sea	216		19	%	128		25	%	457		22	%	399		26	%	North Sea	307		17	%	216		19	%	635		18	%	457		22	%
Total(1)	Total(1)	$	1,141	100	%	$	513	100	%	$	2,132	100	%	$	1,545	100	%	Total(1)	$	1,863	100	%	$	1,141	100	%	$	3,580	100	%	$	2,132	100	%

Natural Gas Revenues:	Natural Gas Revenues:																	Natural Gas Revenues:
United States	United States	$	134	59	%	$	53	41	%	$	345	64	%	$	92	36	%	United States	$	281	65	%	$	134	59	%	$	464	57	%	$	345	64	%
Egypt(1)	Egypt(1)	65		29	%	70		54	%	135		25	%	135		54	%	Egypt(1)	88		20	%	65		29	%	186		23	%	135		25	%
North Sea	North Sea	27		12	%	7		5	%	58		11	%	26		10	%	North Sea	64		15	%	27		12	%	163		20	%	58		11	%
Total(1)	Total(1)	$	226	100	%	$	130	100	%	$	538	100	%	$	253	100	%	Total(1)	$	433	100	%	$	226	100	%	$	813	100	%	$	538	100	%

NGL Revenues:	NGL Revenues:																	NGL Revenues:
United States	United States	$	141	96	%	$	50	93	%	$	261	95	%	$	121	90	%	United States	$	214	93	%	$	141	96	%	$	418	92	%	$	261	95	%
Egypt(1)	Egypt(1)	2		1	%	1		2	%	4		1	%	4		3	%	Egypt(1)	3		1	%	2		1	%	6		2	%	4		1	%
North Sea	North Sea	4		3	%	3		5	%	10		4	%	10		7	%	North Sea	12		6	%	4		3	%	28		6	%	10		4	%
Total(1)	Total(1)	$	147	100	%	$	54	100	%	$	275	100	%	$	135	100	%	Total(1)	$	229	100	%	$	147	100	%	$	452	100	%	$	275	100	%

Oil and Gas Revenues:	Oil and Gas Revenues:																	Oil and Gas Revenues:
United States	United States	$	768	51	%	$	301	43	%	$	1,447	49	%	$	839	43	%	United States	$	1,149	46	%	$	768	51	%	$	2,135	44	%	$	1,447	49	%
Egypt(1)	Egypt(1)	499		33	%	258		37	%	973		33	%	659		34	%	Egypt(1)	993		39	%	499		33	%	1,884		39	%	973		33	%
North Sea	North Sea	247		16	%	138		20	%	525		18	%	435		23	%	North Sea	383		15	%	247		16	%	826		17	%	525		18	%
Total(1)	Total(1)	$	1,514	100	%	$	697	100	%	$	2,945	100	%	$	1,933	100	%	Total(1)	$	2,525	100	%	$	1,514	100	%	$	4,845	100	%	$	2,945	100	%

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

3233

Production

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


		For the Quarter Ended June 30,			For the Six Months Ended, June 30,				For the Quarter Ended June 30,			For the Six Months Ended, June 30,
		2021	Increase (Decrease)	2020	2021	Increase (Decrease)	2020		2022	Increase (Decrease)	2021	2022	Increase (Decrease)	2021
Oil Volume (b/d)	Oil Volume (b/d)							Oil Volume (b/d)
United States	United States	82,852	(12)%	94,471	75,313	(23)%	98,042	United States	64,759	(22)%	82,852	67,184	(11)%	75,313
Egypt(1)(2)	Egypt(1)(2)	71,182	(11)%	79,839	71,673	(6)%	76,509	Egypt(1)(2)	85,502	20%	71,182	85,261	19%	71,673
North Sea	North Sea	31,992	(32)%	47,016	37,726	(26)%	51,139	North Sea	32,493	2%	31,992	33,860	(10)%	37,726
Total	Total	186,026	(16)%	221,326	184,712	(18)%	225,690	Total	182,754	(2)%	186,026	186,305	1%	184,712

Natural Gas Volume (Mcf/d)	Natural Gas Volume (Mcf/d)							Natural Gas Volume (Mcf/d)
United States	United States	541,088	4%	518,156	524,396	(6)%	557,999	United States	457,459	(15)%	541,088	467,493	(11)%	524,396
Egypt(1)(2)	Egypt(1)(2)	256,262	(8)%	279,561	267,145	—%	267,070	Egypt(1)(2)	346,424	35%	256,262	366,390	37%	267,145
North Sea	North Sea	36,769	(30)%	52,612	43,268	(28)%	59,945	North Sea	42,802	16%	36,769	40,645	(6)%	43,268
Total	Total	834,119	(2)%	850,329	834,809	(6)%	885,014	Total	846,685	2%	834,119	874,528	5%	834,809

NGL Volume (b/d)	NGL Volume (b/d)							NGL Volume (b/d)
United States	United States	68,492	(2)%	69,759	63,183	(16)%	75,570	United States	59,267	(13)%	68,492	60,482	(4)%	63,183
Egypt(1)(2)	Egypt(1)(2)	553	(39)%	909	568	(38)%	914	Egypt(1)(2)	297	(46)%	553	394	(31)%	568
North Sea	North Sea	1,095	(37)%	1,733	1,231	(36)%	1,934	North Sea	1,195	9%	1,095	1,345	9%	1,231
Total	Total	70,140	(3)%	72,401	64,982	(17)%	78,418	Total	60,759	(13)%	70,140	62,221	(4)%	64,982

BOE per day(3)	BOE per day(3)							BOE per day(3)
United States	United States	241,525	(4)%	250,589	225,895	(15)%	266,612	United States	200,269	(17)%	241,525	205,582	(9)%	225,895
Egypt(1)(2)	Egypt(1)(2)	114,445	(10)%	127,342	116,765	(4)%	121,934	Egypt(1)(2)	143,536	25%	114,445	146,720	26%	116,765
North Sea(4)	North Sea(4)	39,216	(32)%	57,517	46,169	(27)%	63,064	North Sea(4)	40,822	4%	39,216	41,979	(9)%	46,169
Total	Total	395,186	(9)%	435,448	388,829	(14)%	451,610	Total	384,627	(3)%	395,186	394,281	1%	388,829

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


		For the Quarter Ended June 30,		For the Six Months Ended June 30,			For the Quarter Ended June 30,		For the Six Months Ended June 30,
		2021	2020	2021	2020		2022	2021	2022	2021
Oil (b/d)	Oil (b/d)	135,494	171,897	135,408	177,762	Oil (b/d)	141,432	135,494	137,934	135,408
Natural Gas (Mcf/d)	Natural Gas (Mcf/d)	578,380	642,003	590,756	648,706	Natural Gas (Mcf/d)	555,694	578,380	576,637	590,756
NGL (b/d)	NGL (b/d)	866	1,649	881	1,715	NGL (b/d)	464	866	599	881

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


		For the Quarter Ended June 30,		For the Six Months Ended June 30,			For the Quarter Ended June 30,		For the Six Months Ended June 30,
		2021	2020	2021	2020		2022	2021	2022	2021
Oil (b/d)	Oil (b/d)	23,759	26,609	23,923	25,604	Oil (b/d)	28,516	23,759	28,423	23,923
Natural Gas (Mcf/d)	Natural Gas (Mcf/d)	85,574	92,625	89,235	89,148	Natural Gas (Mcf/d)	115,534	85,574	122,112	89,235
NGL (b/d)	NGL (b/d)	184	303	189	304	NGL (b/d)	99	184	131	189

(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 second ~~quarter~~quarters of 2022 and 2021 ~~and 2020~~ were ~~41,941~~38,029 boe/d and ~~54,996~~41,941 boe/d, respectively, and ~~48,208~~40,833 boe/d and ~~64,133~~48,208 boe/d for the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively. Sales volumes may vary from production volumes as a result of the timing of ~~liftings in the Beryl field.~~liftings.

3334

Pricing

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


		For the Quarter Ended June 30,					For the Six Months Ended, June 30,						For the Quarter Ended June 30,					For the Six Months Ended, June 30,
		2021		Increase (Decrease)	2020		2021		Increase (Decrease)	2020			2022		Increase (Decrease)	2021		2022		Increase (Decrease)	2021
Average Oil Price - Per barrel	Average Oil Price - Per barrel											Average Oil Price - Per barrel
United States	United States	$	65.32	184%	$	23.02	$	61.68	76%	$	35.09	United States	$	110.98	70%	$	65.32	$	103.05	67%	$	61.68
Egypt	Egypt	66.70		159%	25.80		64.30		72%	37.36		Egypt	115.97		74%	66.70		109.65		71%	64.30
North Sea	North Sea	68.34		117%	31.55		63.48		51%	41.94		North Sea	113.77		66%	68.34		107.47		69%	63.48
Total	Total	66.40		158%	25.77		63.06		68%	37.44		Total	113.79		71%	66.40		106.87		69%	63.06

Average Natural Gas Price - Per Mcf	Average Natural Gas Price - Per Mcf											Average Natural Gas Price - Per Mcf
United States	United States	$	2.73	142%	$	1.13	$	3.63	303%	$	0.90	United States	$	6.75	147%	$	2.73	$	5.48	51%	$	3.63
Egypt	Egypt	2.80		3%	2.73		2.80		1%	2.78		Egypt	2.78		(1)%	2.80		2.80		—	2.80
North Sea	North Sea	8.10		466%	1.43		7.43		208%	2.41		North Sea	18.15		124%	8.10		24.72		233%	7.43
Total	Total	2.99		78%	1.68		3.56		127%	1.57		Total	5.65		89%	2.99		5.16		45%	3.56

Average NGL Price - Per barrel	Average NGL Price - Per barrel											Average NGL Price - Per barrel
United States	United States	$	22.72	191%	$	7.81	$	22.84	160%	$	8.77	United States	$	39.79	75%	$	22.72	$	38.20	67%	$	22.84
Egypt	Egypt	38.10		82%	20.97		41.49		57%	26.36		Egypt	75.14		97%	38.10		76.80		85%	41.49
North Sea	North Sea	38.79		91%	20.35		44.21		51%	29.29		North Sea	71.71		85%	38.79		73.29		66%	44.21
Total	Total	23.10		179%	8.28		23.41		147%	9.48		Total	40.97		77%	23.10		39.63		69%	23.41

Second-Quarter ~~2021~~2022 compared to Second-Quarter ~~2020~~2021

Crude Oil Crude oil revenues for the second quarter of ~~2021~~2022 totaled ~~$1.1~~$1.9 billion, a ~~$628~~$722 million increase from the comparative ~~2020~~2021 quarter. A ~~158~~71 percent increase in average realized prices increased second-quarter ~~2021~~2022 oil revenues by $810 million compared to the prior-year quarter, while 16 percent lower average daily production decreased revenues by $182 million. Crude oil revenues accounted for 75 percent of total oil and gas production revenues and 47 percent of worldwide production in the second quarter of 2021. The Company’s worldwide oil production decreased 35.3 Mb/d to 186.0 Mb/d during the second quarter of 2021 from the comparative prior-year period, primarily a result of natural production decline across all countries and extended operational downtime and extended platform turnaround work in the North Sea. Crude oil prices realized in the second quarter of 2021 averaged $66.40 per barrel, compared to $25.77 per barrel in the comparative prior-year quarter.

~~Natural Gas~~ Gas revenues for the second quarter of 2021 totaled $226 million, a $96 million increase from the comparative 2020 quarter. A 78 percent increase in average realized prices increased second-quarter 2021 natural gas revenues by $100$814 million compared to the prior-year quarter, while 2 percent lower average daily production decreased revenues by $4$92 million. ~~Natural gas~~Crude oil revenues accounted for 1574 percent of total oil and gas production revenues and 3548 percent of worldwide production in the second quarter of 2022. The Company’s worldwide oil production decreased 3.3 Mb/d to 182.8 Mb/d during the second quarter of 2022 from the comparative prior-year period, primarily a result of natural production decline across all assets, offset by an 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 second quarter of 2022 totaled $433 million, a $207 million increase from the comparative 2021 quarter. An 89 percent increase in average realized prices increased second-quarter 2022 natural gas revenues by $202 million compared to the prior-year quarter, while 2 percent higher average daily production increased revenues by $5 million. Natural gas revenues accounted for 17 percent of total oil and gas production revenues and 37 percent of worldwide production during the second quarter of ~~2021.~~2022. The Company’s worldwide natural gas production ~~decreased 16~~increased 12.6 MMcf/d to ~~834~~847 MMcf/d during the second quarter of ~~2021~~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 and increased production in the North Sea due to lower operational downtime as compared to the second quarter of 2021. These increases were partially offset by natural production decline across all ~~countries~~assets and ~~extended operational downtime~~the Company’s divestiture of non-core assets in the ~~North Sea, offset by increased completion activity in~~Permian Basin during the ~~U.S.~~first quarter of 2022.

NGL NGL revenues for the second quarter of ~~2021~~2022 totaled ~~$147~~$229 million, a ~~$93~~$82 million increase from the comparative ~~2020~~2021 quarter. A ~~179~~77 percent increase in average realized prices increased second-quarter ~~2021~~2022 NGL revenues by ~~$98~~$114 million compared to the prior-year quarter, while 313 percent lower average daily production decreased revenues by $5$32 million. NGL revenues accounted for 109 percent of total oil and gas production revenues and 1815 percent of worldwide production during the second quarter of ~~2021.~~2022. The Company’s worldwide NGL production decreased ~~2.3~~9.4 Mb/d to ~~70.1~~60.8 Mb/d during the second quarter of ~~2021~~2022 from the comparative prior-year period, primarily a result of natural production decline across all ~~countries.~~assets and the Company’s divestiture of non-core assets in the Permian Basin during the first quarter of 2022.

3435

Year-to-Date ~~2021~~2022 compared to Year-to-Date ~~2020~~2021

Crude Oil Crude oil revenues for the first six months of ~~2021~~2022 totaled ~~$2.1~~$3.6 billion, a ~~$0.6~~$1.4 billion increase from the comparative ~~2020~~2021 period. A 6869 percent increase in average realized prices increased ~~2021~~ oil revenues for the 2022 period by ~~$1.1~~$1.4 billion compared to the prior-year period, while ~~18 percent lower~~the change in average daily production ~~decreased revenues by $471 million.~~was insignificant compared to the prior-year period. Crude oil revenues accounted for 7374 percent of total oil and gas production revenues and 47 percent of worldwide production for the first six months of ~~2021.~~2022. Crude oil prices realized during the first six months of ~~2021~~2022 averaged ~~$63.06~~$106.87 per barrel, compared to ~~$37.44~~$63.06 per barrel in the comparative prior-year period. The Company’s worldwide oil production ~~decreased 41.0~~increased 1.6 Mb/d to ~~184.7~~186.3 Mb/d in the first six months of ~~2021~~2022 compared to the prior-year period, primarily a ~~result~~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 ~~countries, extended operational downtime, and extended platform turnaround work in the North Sea.~~assets.

Natural GasGas revenues for the first six months of ~~2021~~2022 totaled ~~$538~~$813 million, a ~~$285~~$275 million increase from the comparative ~~2020~~2021 period. A ~~127~~45 percent increase in average realized prices increased ~~2021~~ natural gas revenues for the 2022 period by ~~$321~~$241 million compared to the prior-year period, while 65 percent ~~lower~~higher average daily production ~~decreased~~increased revenues by ~~$36 million.~~$34 million compared to the prior-year period. Natural gas revenues accounted for 1817 percent of total oil and gas production revenues and 3637 percent of worldwide production for the first six months of ~~2021.~~2022. Natural gas prices realized during the first six months of ~~2021~~2022 averaged ~~$3.56~~$5.16 per Mcf, compared to ~~$1.57~~$3.56 per Mcf in the comparative prior-year period. ~~Gas prices for the U.S. during the first six months of 2021 also reflect the extreme price volatility during the month of February due to the Texas freeze event.~~ The Company’s worldwide natural gas production ~~decreased 50~~increased 40 MMcf/d to ~~835~~875 MMcf/d in the first six months of ~~2021~~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 natural production decline across all ~~countries, impacts of winter storms in the U.S., and extended operational downtime and platform turnaround work in the North Sea.~~assets.

NGL NGL revenues for the first six months of ~~2021~~2022 totaled ~~$275~~$452 million, a ~~$140~~$177 million increase from the comparative ~~2020~~2021 period. A ~~147~~69 percent increase in average realized prices increased ~~2021~~ NGL revenues for the 2022 period by ~~$199~~$191 million compared to the prior-year period, while 174 percent lower average daily production decreased revenues by ~~$59 million.~~$14 million compared to the prior-year period. NGL revenues accounted for 9 percent of total oil and gas production revenues and 1716 percent of worldwide production for the first six months of ~~2021.~~2022. NGL prices realized during the first six months of ~~2021~~2022 averaged ~~$23.41~~$39.63 per barrel, compared to ~~$9.48~~$23.41 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased ~~13.4~~2.8 Mb/d to ~~65.0~~62.2 Mb/d in the first six months of ~~2021~~2022 compared to the prior-year period, primarily a result of natural production decline across all ~~countries and the impacts of winter storms in the U.S.~~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 $32 million ~~and $31 million~~ during the second ~~quarters~~quarter of 2021 and ~~2020, respectively,~~$16 million and $64 ~~million and $72~~ million during the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively. These ~~affiliated~~ revenues ~~are~~were eliminated upon consolidation. ~~Changes in revenue compared to the prior periods were primarily driven by fluctuations in natural gas throughput volumes processed by Altus for the Company’s Alpine High production.~~

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 ~~$242~~$522 million and ~~$55~~$242 million during the second quarters of ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$682~~$871 million and ~~$163~~$682 million during the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively. Purchased oil and gas sales were offset by associated purchase costs of ~~$262~~$528 million and ~~$46~~$262 million during the second quarters of ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$756~~$879 million and ~~$132~~$756 million during the first six months of 2022 and 2021, ~~and 2020,~~ respectively. ~~When compared to the prior-year periods, gross~~Gross purchased oil and gas sales values ~~and the associated net losses~~were higher in the second quarter and first six months of ~~2021 increased as a result of production shortfalls following reduced capital investment and drilling activity in 2020. The year-to-date net loss was exacerbated by extreme price volatility~~2022 primarily due to higher average natural gas prices during the ~~month of February due to Winter Storm Uri in Texas.~~2022 periods.

3536

Operating Expenses

The Company’s operating expenses were as follows:


											For the Quarter Ended June 30,				For the Six Months Ended June 30,
		For the Quarter Ended June 30,				For the Six Months Ended June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions)									(In millions)
Lease operating expenses	Lease operating expenses	$	311	$	264	$	575	$	599	Lease operating expenses	$	359	$	311	$	703	$	575
Gathering, processing, and transmission	Gathering, processing, and transmission	61		72		119		143		Gathering, processing, and transmission	94		61		175		119
Purchased oil and gas costs	Purchased oil and gas costs	262		46		756		132		Purchased oil and gas costs	528		262		879		756
Taxes other than income	Taxes other than income	51		23		95		56		Taxes other than income	78		51		148		95
Exploration	Exploration	26		72		75		129		Exploration	56		26		98		75
General and administrative	General and administrative	86		94		169		162		General and administrative	89		86		245		169
Transaction, reorganization, and separation	Transaction, reorganization, and separation	4		10		4		37		Transaction, reorganization, and separation	3		4		17		4
Depreciation, depletion, and amortization:	Depreciation, depletion, and amortization:									Depreciation, depletion, and amortization:
Oil and gas property and equipment	Oil and gas property and equipment	322		387		634		918		Oil and gas property and equipment	269		322		547		634
Gathering, processing, and transmission assets	Gathering, processing, and transmission assets	19		19		38		39		Gathering, processing, and transmission assets	1		19		6		38
Other assets	Other assets	10		12		21		27		Other assets	8		10		16		21
Asset retirement obligation accretion	Asset retirement obligation accretion	28		27		56		54		Asset retirement obligation accretion	29		28		58		56
Impairments		—		20		—		4,492

Financing costs, net	Financing costs, net	107		(34)		217		69		Financing costs, net	76		107		228		217
Total Operating Expenses	Total Operating Expenses	$	1,287	$	1,012	$	2,759	$	6,857	Total Operating Expenses	$	1,590	$	1,287	$	3,120	$	2,759

Lease Operating Expenses (LOE)

LOE increased ~~$47~~$48 million and ~~decreased $24~~$128 million in the second quarter and the first six months of ~~2021,~~2022, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 2820 percent and 1222 percent in the second quarter and the first six months of ~~2021,~~2022, respectively, from the comparative prior-year periods. The increase was driven by overall higher ~~turnaround~~labor costs and ~~maintenance costs in the North Sea, strengthening foreign exchange rates against the U.S. dollar, increased workover activity in the U.S. in the second quarter of 2021, and per-unit~~ operating costs trending with higher oil and gas ~~prices.~~prices and global inflation. These increases were coupled with higher workover activity in the U.S. and in the North Sea in the second quarter and the first six months of 2022. LOE costs for the first six months of 2022 were also impacted by mark-to-market adjustments for 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.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:


											For the Quarter Ended June 30,				For the Six Months Ended, June 30,
		For the Quarter Ended June 30,				For the Six Months Ended, June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions)									(In millions)
Third-party processing and transmission costs	Third-party processing and transmission costs	$	53	$	62	$	104	$	123	Third-party processing and transmission costs	$	68	$	53	$	134	$	104
Midstream service affiliate costs		32		32		63		72
Midstream service costs - ALTM										Midstream service costs - ALTM	—		32		18		63
Midstream service costs - Kinetik										Midstream service costs - Kinetik	26		—		36		—
Upstream processing and transmission costs	Upstream processing and transmission costs	85		94		167		195		Upstream processing and transmission costs	94		85		188		167
Midstream operating expenses	Midstream operating expenses	8		10		15		20		Midstream operating expenses	—		8		5		15
Intersegment eliminations	Intersegment eliminations	(32)		(32)		(63)		(72)		Intersegment eliminations	—		(32)		(18)		(63)
Total Gathering, processing, and transmission	Total Gathering, processing, and transmission	$	61	$	72	$	119	$	143	Total Gathering, processing, and transmission	$	94	$	61	$	175	$	119

GPT costs ~~decreased $11~~increased $33 million and ~~$24~~$56 million in the second quarter and the first six months ~~2021,~~of 2022, respectively, from the comparative prior-year periods. Third-party processing and transmission costs ~~decreased $9~~increased $15 million and ~~$19~~$30 million in the second quarter and the first six months of ~~2021,~~2022, respectively, from the comparative prior-year ~~periods, primarily driven by a decrease~~periods. The increase in ~~contracted pricing and lower processed volumes. Midstream service affiliate~~third-party costs ~~remained flat in~~for the second quarter ~~of 2021~~ and ~~decreased $9 million in~~ the first six months of ~~2021, compared to their respective prior-year periods. The overall decrease in the first six months of 2021~~2022 was primarily driven by ~~lower throughput~~an increase in average transportation rates during the year. Costs for services provided by ALTM in the first quarter of ~~rich natural gas volumes at Alpine High.~~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 ~~operating expenses, primarily incurred~~services provided by ~~Altus Midstream, decreased $2~~Kinetik totaled $26 million and $5$36 million in the second quarter and the first six months of ~~2021,~~2022, respectively, ~~from~~and will continue to result in higher GPT costs in future periods as compared to periods preceding the ~~comparative prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.~~

ALTM deconsolidation.

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $528 million and $879 million during the second quarter and the first six months of 2022, respectively, compared to $262 million and $756 million during the second quarter and the first six months of 2021, ~~respectively, compared to $46 million and $132 million during the second quarter and the first six months of 2020,~~ respectively. Purchased oil and gas costs were offset by associated purchase sales of $522 million and $871 million during the second quarter and the first six months of 2022, respectively, compared to $242 million and $682 million during the second quarter and the first six months of 2021, respectively, ~~compared to $55 million and $163 million during the second quarter and the first six months of 2020, respectively,~~ as further discussed above.

Taxes Other Than Income

Taxes other than income increased ~~$28~~$27 million and ~~$39~~$53 million from the second quarter and the first six months of ~~2020,~~2021, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the same prior-year ~~period.~~periods.

Exploration Expenses

The Company’s exploration expenses were as follows:


											For the Quarter Ended June 30,				For the Six Months Ended, June 30,
		For the Quarter Ended June 30,				For the Six Months Ended, June 30,					2022		2021		2022		2021
		2021		2020		2021		2020
		(In millions)									(In millions)
Unproved leasehold impairments	Unproved leasehold impairments	$	3	$	31	$	21	$	50	Unproved leasehold impairments	$	2	$	3	$	6	$	21
Dry hole expense	Dry hole expense	6		23		25		47		Dry hole expense	36		6		41		25
Geological and geophysical expense	Geological and geophysical expense	6		4		10		7		Geological and geophysical expense	3		6		18		10
Exploration overhead and other	Exploration overhead and other	11		14		19		25		Exploration overhead and other	15		11		33		19
Total Exploration	Total Exploration	$	26	$	72	$	75	$	129	Total Exploration	$	56	$	26	$	98	$	75

Exploration expenses ~~decreased $46~~increased $30 million and ~~$54~~$23 million from the second quarter and the first six months of ~~2020,~~2021, respectively, primarily the result of ~~lower~~higher dry hole ~~expense~~expenses and exploration overhead, a function of ~~decreased~~increased exploration activities. ~~The Company also had~~These increases were partially offset by lower unproved leasehold impairments driven by improved commodity prices.

General and Administrative (G&A) Expenses

G&A expenses ~~decreased $8~~increased $3 million inand $76 million from the second quarter ~~of 2021 compared to the second quarter of 2020,~~ and ~~increased $7 million in~~ the first six months of 2021, ~~compared to the first six months of 2020.~~respectively. The ~~reduction in second-quarter 2021 G&A compared to the prior-year quarter was driven by organizational redesign efforts during 2019 and 2020. The~~year-over-year increase ~~in the first six months of 2021 from the comparative prior-year period~~ was primarily ~~related to~~driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price ~~offset by lower overhead during~~and anticipated achievement of performance and financial objectives as defined in the ~~year as previously discussed.~~stock award plans. Higher overall wages across the Company also impacted G&A expenses compared to the prior-year period.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $6$1 million and ~~$33~~increased $13 million from the second quarter and the first six months of ~~2020, respectively, driven by~~2021, respectively. The increase in costs ~~associated with~~during the ~~Company’s reorganization efforts incurred in~~first six months of 2022 compared to the ~~prior year.~~same prior-year period was primarily a result of transaction costs from the BCP Business Combination.

In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed during 2020.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties decreased ~~$65~~$53 million and ~~$284~~$87 million from the second quarter and the first six months of ~~2020,~~2021, respectively. The Company’s DD&A rate on its oil and gas properties decreased ~~$0.93~~$1.16 per boe and ~~$2.18~~$1.28 per boe from the second quarter and the first six months of ~~2020,~~2021, respectively. The decrease on an absolute basis was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT assets remained essentially flat compared to the second quarter and the first six months of 2020.

~~Impairments~~

~~The Company recognized no asset impairments in connection with fair value assessments during the first six months of 2021.~~

The Company recognized $4.5 billion in asset impairments in connection with fair value assessments during the first six months of 2020. During the second quarter of 2020, the Company recognized impairments totaling $20 million related to proved oil and gas properties in Egypt. During the first quarter of 2020, the Company recognized impairments totaling $4.3 billion related to proved oil and gas properties in the U.S., Egypt, and the North Sea, $68 million related to GPT facilitiesdepletion rates in Egypt, ~~$87 million related to goodwill valuations in Egypt, and $18 million related to inventory and other miscellaneous assets, including charges for the early termination of drilling rig leases.~~partially offset by higher production volumes.

Financing Costs, Net

The Company’s Financing costs were as follows:


		For the Quarter Ended June 30,				For the Six Months Ended, June 30,					For the Quarter Ended June 30,				For the Six Months Ended, June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions)									(In millions)
Interest expense	Interest expense	$	110	$	107	$	222	$	214	Interest expense	$	79	$	110	$	169	$	222
Amortization of debt issuance costs	Amortization of debt issuance costs	3		2		5		4		Amortization of debt issuance costs	5		3		7		5
Capitalized interest	Capitalized interest	(2)		(2)		(4)		(6)		Capitalized interest	(5)		(2)		(8)		(4)
Gain on extinguishment of debt		(1)		(140)		(1)		(140)
(Gain) loss on extinguishment of debt										(Gain) loss on extinguishment of debt	—		(1)		67		(1)
Interest income	Interest income	(3)		(1)		(5)		(3)		Interest income	(3)		(3)		(7)		(5)
Total Financing costs, net	Total Financing costs, net	$	107	$	(34)	$	217	$	69	Total Financing costs, net	$	76	$	107	$	228	$	217

Net financing costs ~~increased $141~~decreased $31 million and ~~$148~~increased $11 million from the second quarter and the first six months of ~~2020, respectively, driven~~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. During the first six months of 2022, the lower interest expense was more than offset by ~~the $140~~a $67 million ~~gain~~loss on extinguishment of debt ~~recorded~~recognized in the ~~second~~first quarter of ~~2020.~~2022.

Provision for Income Taxes

On May 26, 2022, the ~~second quarter and first six months~~U.K. Chancellor announced a new tax on the profits of 2020, the Company’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets and impairments recorded during the period. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas ~~asset impairments, a goodwill impairment, and an increase~~companies operating in the ~~amount~~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 tax rate and will be effective for the period of ~~valuation allowance against its~~May 26, 2022, through December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation will be recorded in the period of enactment. Therefore, in the third quarter of 2022, the Company expects to record a deferred tax ~~assets.~~expense of approximately $230 million to $250 million related to the remeasurement of the June 30, 2022 U.K. deferred tax liability.

The Company 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.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. ~~These changes~~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 capital investment for the second quarter of ~~2021~~2022 was below its ~~planned budget announced earlier~~guidance for the period as some activity shifted to later in the year, ~~but~~and the Company ~~remains on-track for~~expects its full-year ~~guidance and~~ estimated upstream capital ~~program of $1.1~~to be approximately $1.725 billion. ~~The program consists of approximately $900 million for development activities across its portfolio and approximately $200 million for exploration activities, predominantly in Suriname.~~This is nearly 8 percent higher than initial guidance, primarily on increased Suriname drilling activity.

The Company believes ~~the~~its available liquidity and capital resource alternatives, ~~available to the Company,~~ combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including 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 ~~subsidiary~~ borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs. 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 ~~Apache Corporation’s~~the Company’s Annual Report on Form 10-K ~~of Apache Corporation~~ for the fiscal year ended December 31, ~~2020.~~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.~~presented:

For the Six Months Ended
June 30,
2021 2020
(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities $ 1,640 $ 586
Proceeds from Apache credit facility, net — 565
Proceeds from Altus credit facility, net 33 97
Proceeds from asset divestitures 181 126
Total Sources of Cash and Cash Equivalents 1,854 1,374
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property(1)
$ (558) $ (838)
Additions to Altus gathering, processing, and transmission facilities(1)
(1) (25)
Leasehold and property acquisitions (3) (3)
Contributions to Altus equity method interests (24) (154)
Payments on Apache credit facility, net (150) —
Payments on fixed-rate debt (20) (264)
Dividends paid to APA common stockholders (19) (104)
Distributions to noncontrolling interest - Egypt (60) (40)
Distributions to Altus Preferred Unit limited partners (23) —
Other (9) (58)
Total Uses of Cash and Cash Equivalents (867) (1,486)
Increase (decrease) in cash and cash equivalents $ 987 $ (112)

~~(1) The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Quarterly Report on Form 10-Q, which include accruals.~~


	For the Six Months Ended June 30,
	2022		2021

	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,426	$	1,640

Proceeds from Altus credit facility, net	—		33
Proceeds from asset divestitures	751		181
Proceeds from sale of Kinetik shares	224		—


Total Sources of Cash and Cash Equivalents	3,401		1,854
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property	$	741	$	558

Leasehold and property acquisitions	26		3

Payments on revolving credit facilities, net	267		150
Payments on fixed-rate debt	1,370		20
Dividends paid to APA common stockholders	86		19
Distributions to noncontrolling interest - Egypt	159		60
Distributions to Altus Preferred Unit limited partners	11		23

Treasury stock activity, net	552		—
Deconsolidation of Altus cash and cash equivalents	143		—
Other	66		34
Total Uses of Cash and Cash Equivalents	3,421		867
Increase (decrease) in cash and cash equivalents	$	(20)	$	987

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~~$786 million from the first six months of ~~2020,~~2021, primarily due to higher commodity ~~prices.~~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~~statement of ~~Consolidated Cash Flows~~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 six months of 2020, Apache borrowed $565 million under its revolving credit facility.~~

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity method pipelines ~~has historically~~in early 2021 required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first six months of 2021, ~~and 2020,~~ Altus Midstream LP borrowed $33 million ~~and $97 million, respectively,~~ under its revolving credit facility to meet this ~~short fall. With~~shortfall. Prior to the ~~midstream infrastructure complete and all~~deconsolidation of ~~the equity method interest pipelines now~~Altus on February 22, 2022, there were no additional borrowings under this facility in ~~service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program during 2021.~~2022.

Proceeds from Asset Divestitures The Company received ~~$181~~$751 million and ~~$126~~$181 million of proceeds from the divestiture of certain non-core assets during the first six months of 2022 and 2021, ~~and 2020,~~ respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first six months of 2022. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were ~~$558~~$741 million and ~~$838~~$558 million during the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively. The ~~decrease~~increase in capital investment is reflective of the increase in the Company’s ~~reduced~~ capital ~~program to align with anticipated operating cash flows.~~program. The Company operated an average of 20 drilling rigs during the second quarter of 2022, compared to an average of 10 drilling rigs during the second quarter of ~~2021, compared to an average of 12 drilling rigs during the second quarter of 2020.~~

~~Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities~~ The Company’s cash expenditures for GPT facilities totaled $1 million and $25 million during the first six months of 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for the remainder of 2021 to be minimal.2021.

Leasehold and Property Acquisitions ~~The~~During the first six months of 2022 and 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $26 million and $3 million, ~~during the first six months of 2021 and 2020.~~

~~Contributions to Altus Equity Method Interests~~ Altus contributed $24 million and $154 million in cash during the first six months of 2021 and 2020, respectively, for equity interests in the equity method interest pipelines. For more information regarding the Company’s equity method interests, refer to ~~Note 6—Equity Method Interests~~ ~~in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.~~respectively.

Payments on ~~Apache~~Revolving Credit ~~Facility~~Facilities APA and Apache paid down a net of $267 million and $150 million during the first six months of 2022 and 2021, respectively, on its revolving credit ~~facility borrowings.~~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 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 an aggregate $1 million. The Company recognized a $1 million loss on these repurchases.

During the first six 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.

During the second quarter of 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $410 million for an aggregate purchase price of $267 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $147 million. These repurchases resulted in a $140 million net gain on extinguishment of debt, which is included in “Financing costs, net” in the Company’s statement of consolidated operations. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under Apache’s revolving credit facility.

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

Dividends The Company paid ~~$19~~$86 million and ~~$104~~$19 million during the first six months of ~~2021~~2022 and ~~2020,~~2021, respectively, for dividends on its common stock. InDuring the ~~first~~third quarter of ~~2020,~~2021, the Company’s Board of Directors approved ~~a reduction~~an increase in ~~the Company’s~~its quarterly dividend per share from ~~$0.25~~$0.025 to $0.0625 and, in the fourth quarter of 2021, a further increase to $0.125 per ~~share to $0.025 per share, effective for all dividends payable after March 12, 2020.~~share.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid ~~$60~~$159 million and ~~$40~~$60 million during the first six months of ~~2021~~2022 and ~~2020,~~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 $23 million ~~during the first six months of 2021~~ in cash distributions to its limited partners holding Preferred ~~Units. No cash distributions were made~~Units during the first six months of ~~2020.~~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 six months of 2022, the Company repurchased 14.2 million shares at an average price of $38.79 per share totaling $552 million, and as of June 30, 2022, the Company had remaining authorization to repurchase 34.6 million shares. No shares were repurchased during the six months ended June 30, 2021.

Liquidity

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


							June 30, 2022		December 31, 2021
		June 30, 2021		December 31, 2020
		(In millions)					(In millions)
Cash and cash equivalents	Cash and cash equivalents	$	1,249	$	262	Cash and cash equivalents	$	282	$	302
Total debt - Apache	Total debt - Apache	7,978		8,148		Total debt - Apache	5,285		6,853
Total debt - Altus	Total debt - Altus	657		624		Total debt - Altus	—		657
Total equity (deficit)	Total equity (deficit)	76		(645)		Total equity (deficit)	1,505		(717)
Available committed borrowing capacity - Apache		3,204		2,944
Available committed borrowing capacity under syndicated credit facilities						Available committed borrowing capacity under syndicated credit facilities	2,421		2,426
Available committed borrowing capacity - Altus	Available committed borrowing capacity - Altus	141		176		Available committed borrowing capacity - Altus	—		141

Cash and Cash Equivalents As of June 30, ~~2021,~~2022, the Company had ~~$1.2 billion~~$282 million in cash and cash ~~equivalents, of which approximately $75 million was held by Altus.~~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 June 30, ~~2021,~~2022, the Company had ~~$8.6~~$5.3 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of June 30, ~~2021,~~2022, current debt included ~~$213~~$123 million, ~~net~~carrying value, of ~~discount, of 3.625%~~Apache’s 2.625% senior notes due ~~April~~January 15, ~~2022~~2023 and $2 million of finance lease obligations.

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

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a ~~letter~~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 ~~subfacility of~~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 ~~$3.0 billion,~~an aggregate principal amount of ~~which $2.08 billion was committed as~~US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of ~~June 30, 2021. The facility~~indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.less than US$1.0 billion.

As of June 30, 2022, there were $275 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 no$542 million of borrowings and an aggregate ~~£561~~£748 million and $20 million in letters of credit outstanding under ~~this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility.~~the Former Facility. The ~~outstanding~~ letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.

~~Apache and Altus Midstream LP were in compliance with the terms of their respective credit facilities as of June 30, 2021.~~

Uncommitted Credit Facilities Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, ~~2021 and December 31, 2020,~~2022, there were no borrowings and ~~£34~~£117 million and $17 million in letters of credit outstanding under these facilities.

~~Commercial Paper Program~~ ~~Apache has not used its commercial paper program during 2021 and terminated the program.~~ As of ~~June 30, 2021 and~~ December 31, ~~2020,~~2021, there were no ~~commercial paper was outstanding.~~borrowings and £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 ~~as described in~~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 ~~Apache Corporation’s~~APA’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021. There have been no material changes to the contractual obligations described therein.

Potential ~~Asset Retirement~~Decommissioning Obligations on Sold Properties

The ~~Company has~~Company’s subsidiaries have potential exposure to future obligations related to divested properties. ~~Apache~~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 ~~the Company’s~~such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, ~~APA~~APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, ~~APA~~such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, ~~the Company~~Apache sold its GOM Shelf operations and properties ~~(Legacy~~and its GOM ~~Assets)~~operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, ~~the Company~~Apache received cash consideration of $3.75 billion and Fieldwood assumed ~~$1.5 billion of discounted asset abandonment liabilities as of~~ the ~~disposition date.~~obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment ~~liabilities,~~obligations, Fieldwood posted letters of credit in favor of ~~the Company~~Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a ~~trust account (Trust A),~~beneficiary and which iswere funded by ~~a 10 percent~~two net profits ~~interest~~interests (NPIs) depending on future oil ~~prices and of which the Company is the beneficiary.~~prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which ~~the Company~~Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of ~~Credit.~~Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, ~~the Company~~Apache holds two bonds (Bonds) and ~~the remaining~~five Letters of Credit backed by investment-grade counterparties to secure Fieldwood’s asset retirement obligations ~~(AROs)~~ on the Legacy GOM Assets as and when ~~such abandonment and decommissioning obligations are~~Apache is required to ~~be performed~~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. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Legacy GOM Assets into a standalone company, and proceeds of production of the Legacy GOM Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then the Company expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, the Company has agreed to provide a standby loan of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.

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.

4244

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 ~~result of continuing negative demand implications of~~commodity and financial markets associated with the COVID-19 pandemic, ~~became more apparent.~~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, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets subsequent to the year ended December 31, 2019.~~exposure.

The Company’s average crude oil price realizations increased ~~158~~71 percent from ~~$25.77~~$66.40 per barrel to ~~$66.40~~$113.79 per barrel during the second quarters of ~~2020~~2021 and ~~2021,~~2022, respectively. The Company’s average natural gas price realizations increased 7889 percent from ~~$1.68~~$2.99 per Mcf to ~~$2.99~~$5.65 per Mcf during the second quarters of ~~2020~~2021 and ~~2021,~~2022, respectively. The Company’s average NGL price realizations increased ~~179~~77 percent from ~~$8.28~~$23.10 per barrel to ~~$23.10~~$40.97 per barrel during the second quarters of ~~2020~~2021 and ~~2021,~~2022, respectively. Based on average daily production for the second quarter of ~~2021,~~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 $17 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 June 30, ~~2021,~~2022, the Company had open natural gas derivatives not designated as cash flow hedges in a liability position with a fair value of ~~less than $1~~$54 million. A 10 percent increase in gas prices would increase the liability by approximately $3$10 million, while a 10 percent decrease in gas prices would move the derivatives to an asset position of $3 million. As of June 30, 2021, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $62 million. A 10 percent increase in oil prices would increase the liability by approximately $57 million, while a 10 percent decrease in oil prices would decrease the liability by approximately ~~$57~~$10 million. These fair value changes assume volatility based on prevailing market parameters atas of June 30, ~~2021.~~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 June 30, ~~2021,~~2022, the Company had ~~$8.0~~$5.0 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of ~~4.98~~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 June 30, ~~2021,~~2022, the Company had approximately ~~$1.2 billion~~$282 million in cash and cash equivalents, approximately 7249 percent of which was invested in money market funds and short-term investments with major financial institutions. As of June 30, ~~2021, Altus Midstream LP had~~2022, there were $275 million of borrowings outstanding ~~borrowings of $657 million~~ under ~~its~~the Company’s syndicated revolving credit ~~facility.~~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. AExcluding the impacts of the foreign exchange contracts discussed below, foreign currency net gain or loss of $6$5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 30, ~~2021.~~2022.

~~The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union.~~ The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. ~~The~~As of June 30, 2022, the Company had no outstanding foreign exchange ~~derivative~~ contracts with a total notional amount of £90 million that are used to reduce its exposure to fluctuating foreign exchange rates for the British pound. A 10 percent strengthening of the British pound against the U.S. dollar would result in a foreign currency net loss associated with these contracts of $1 million, while a 10 percent weakening of the British pound against the U.S. dollar would result in a loss of $18 million as of June 30, ~~2021.~~2022.

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 June 30, ~~2021,~~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 June 30, ~~2021~~2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

4447

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Part I, Item 3—Legal Proceedings of ~~Apache Corporation’s~~the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020~~2021 and Note ~~12—~~11—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

Refer to Part I, Item 1A—Risk Factors of ~~Apache Corporation’s~~the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020 and Part II, Item 1A—Risk Factors of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31,~~ 2021.

Given the nature of ~~their respective businesses,~~its business, Apache Corporation ~~and Altus Midstream Company~~ may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the ~~applicable~~ disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, ~~2021~~2022 and June 30, ~~2021~~2022 and ~~Altus Midstream Company’s~~Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021 and June 30,~~ 2021.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~In 2013 and 2014,~~The following table presents information on shares of common stock repurchased by the ~~Company’s~~Company during the quarter ended June 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)
April 1 to April 30, 2022	1,877,089	$	41.97	1,877,089	39,689,251
May 1 to May 31, 2022	1,920,689	41.50		1,920,689	37,768,562
June 1 to June 30, 2022	3,189,921	41.44		3,189,921	34,578,641
Total	6,987,699	$	41.60

(1) On October 30, 2018, the Company announced that its Board of Directors authorized the ~~purchase~~repurchase of up to 40 million shares of the ~~Company’s~~Company's common ~~stock, and during~~stock. No shares were purchased under this authorization through December 31, 2020. During the fourth quarter of ~~2018,~~2021, the ~~Company’s~~Company's Board of Directors authorized the purchase of ~~up to~~an additional 40 million ~~additional~~ shares of the ~~Company’s~~Company's common stock. Shares may be purchased either in the open market or through privately ~~held~~ negotiated transactions. ~~The Company initiated the buyback program on June 10, 2013, and, through June 30, 2021, had repurchased a total of 40 million shares at an average price of $79.18 per share.~~ The Company is not obligated to acquire any specific number of ~~shares and did not purchase any shares during the first six months of 2021.~~shares.

4548

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-K filed March 1, 2021, SEC File No. 001-40144).

2.1

–

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-K filed March 1, 2021, SEC File No. 001-40144).

3.1

–

3.2

–

Amended and Restated Bylaws of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K dated 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).

10.1

–

Credit Agreement [USD Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, Royal Bank of Canada, HSBC Bank USA, National Association, MUFG Bank, Ltd., Wells Fargo Bank, National Association, Goldman Sachs Bank USA, The Toronto- Dominion Bank, New York Branch, The Bank of Nova Scotia, Houston Branch, Truist Bank, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 2, 2022, SEC File No. 001-40144).

10.2

–

Credit Agreement [GBP Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, The Toronto-Dominion Bank, London Branch, as Syndication Agent, Bank of America, N.A., Royal Bank of Canada, HSBC Bank USA, National Association, MUFG Bank, Ltd., Wells Fargo Bank, N.A. London Branch, Goldman Sachs Bank USA, The Bank of Nova Scotia, Houston Branch, Truist Bank, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed May 2, 2022, 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.

*31.1

–

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.

*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.

*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 June 30, 2021, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.

*101

–

The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 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.SCH

–

Inline XBRL Taxonomy Schema Document.

*101.CAL

–

Inline XBRL Calculation Linkbase Document.

*101.CAL

–

Inline XBRL Calculation Linkbase Document.

*101.DEF

–

Inline XBRL Definition Linkbase Document.

*101.DEF

–

Inline XBRL Definition Linkbase Document.

*101.LAB

–

Inline XBRL Label Linkbase Document.

*101.LAB

–

Inline XBRL Label Linkbase Document.

*101.PRE

–

Inline XBRL Presentation Linkbase Document.

*101.PRE

–

Inline XBRL Presentation Linkbase Document.

*104

–

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*104

–

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith

4649

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:	August ~~5, 2021~~4, 2022	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	August ~~5, 2021~~4, 2022	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

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