10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q 

(Mark One)  

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

For the quarterly period ended September 30, 2021

or

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

For the transition period from _________ to _________

Commission File Number: 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	41-0747868
(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: None

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 ☐

Note: The registrant is a voluntary filer of reports required to be filed by certain companies under Sections 13 or 15(d) of the Securities Exchange Act of 1934.

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

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

Number of shares of registrant’s common stock outstanding as of October 31, 2021 (100% owned by APA Corporation) 1,000 

OMISSION OF CERTAIN INFORMATION

The registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Quarterly Report on Form 10-Q with the reduced disclosure format.

TABLE OF CONTENTS

Item		Page
	PART I - FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS	1
	STATEMENT OF CONSOLIDATED OPERATIONS	1
	STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)	2
	STATEMENT OF CONSOLIDATED CASH FLOWS	3
	CONSOLIDATED BALANCE SHEET	4
	STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST	5
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	7
2.	MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS	30
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	39
4.	CONTROLS AND PROCEDURES	39
	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	40
1A.	RISK FACTORS	40
6.	EXHIBITS	41

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, 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 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;

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the availability of goods and services;

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

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

•terrorism or cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

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

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

•the Company’s expectations with respect to the new operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q) and the associated disclosure implications;

•other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020;

•other risks and uncertainties disclosed in the Company’s third-quarter 2021 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 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 per day.

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

“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.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

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

“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.

“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 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 working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

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

PART I – FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	1,685	$	1,046	$	4,630	$	2,979
Purchased oil and gas sales	374		74		1,056		237
Total revenues	2,059		1,120		5,686		3,216
Derivative instrument gains (losses), net	—		16		45		(262)
Gain (loss) on divestitures, net	(2)		(1)		65		24
Loss on previously sold Gulf of Mexico properties	(446)		—		(446)		—
Other, net	40		9		175		41
	1,651		1,144		5,525		3,019
OPERATING EXPENSES:
Lease operating expenses	316		259		891		858
Gathering, processing, and transmission	68		63		187		206
Purchased oil and gas costs	396		75		1,152		207
Taxes other than income	54		34		149		90
Exploration	21		58		86		187
General and administrative	64		52		226		214
Transaction, reorganization, and separation	4		7		8		44
Depreciation, depletion, and amortization	335		398		1,028		1,382
Asset retirement obligation accretion	29		27		85		81
Impairments	18		—		18		4,492
Financing costs, net	192		99		393		168
	1,497		1,072		4,223		7,929
NET INCOME (LOSS) BEFORE INCOME TAXES	154		72		1,302		(4,910)
Current income tax provision	183		58		463		120
Deferred income tax benefit	(29)		(27)		(51)		(71)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	—		41		890		(4,959)
Net income (loss) attributable to noncontrolling interest - Egypt	49		24		132		(138)
Net income (loss) attributable to noncontrolling interest - Altus	4		2		32		(7)
Net income attributable to Altus Preferred Unit limited partners	30		19		73		56
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	$	(83)	$	(4)	$	653	$	(4,870)

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

1

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	—	$	41	$	890	$	(4,959)
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Share of equity method interests other comprehensive income	—		1		1		—
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	—		42		891		(4,959)
Comprehensive income (loss) attributable to noncontrolling interest - Egypt	49		24		132		(138)
Comprehensive income (loss) attributable to noncontrolling interest - Altus	4		2		32		(7)
Comprehensive income attributable to Altus Preferred Unit limited partners	30		19		73		56
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	$	(83)	$	(3)	$	654	$	(4,870)

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

2

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)

	For the Nine Months Ended September 30,
	2021		2020
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$	890	$	(4,959)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses, net	18		142
Gain on divestitures, net	(65)		(24)
Exploratory dry hole expense and unproved leasehold impairments	57		138
Depreciation, depletion, and amortization	1,028		1,382
Asset retirement obligation accretion	85		81
Impairments	18		4,492
Deferred income tax benefit	(51)		(71)
Loss (gain) on extinguishment of debt	104		(152)
Loss on previously sold Gulf of Mexico properties	446		—
Other, net	(42)		45
Changes in operating assets and liabilities:
Receivables	(274)		202
Inventories	(19)		16
Drilling advances and other current assets	20		(5)
Deferred charges and other long-term assets	(46)		(12)
Accounts payable	195		(211)
Accounts payable to APA Corporation	33		—
Accrued expenses	29		(211)
Deferred credits and noncurrent liabilities	(8)		37
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,418		890
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(673)		(1,075)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(2)		(27)
Leasehold and property acquisitions	(6)		(3)
Contributions to Altus equity method interests	(27)		(286)
Proceeds from sale of oil and gas properties	239		132
Other, net	44		(17)
NET CASH USED IN INVESTING ACTIVITIES	(425)		(1,276)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	290		87
Proceeds from Altus credit facility, net	33		184
Proceeds from note payable to APA Corporation, net	139		—
Fixed-rate debt borrowings	—		1,238
Payments on fixed-rate debt	(1,795)		(980)
Distributions to noncontrolling interest - Egypt	(203)		(61)
Distributions to Altus Preferred Unit limited partners	(34)		(11)
Distributions to APA Corporation	(311)		—
Dividends paid	(9)		(113)
Other, net	(17)		(43)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(1,907)		301
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	86		(85)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262		247
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	348	$	162
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	365	$	341
Income taxes paid, net of refunds	415		153

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

3

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	September 30, 2021		December 31, 2020
	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($109 and $24 related to Altus VIE)	$	348	$	262
Receivables, net of allowance of $99 and $95	1,167		908
Other current assets (Note 6) ($9 and $5 related to Altus VIE)	599		676
Accounts receivable from APA Corporation	55		—
	2,169		1,846
PROPERTY AND EQUIPMENT:
Oil and gas properties	40,205		41,819
Gathering, processing, and transmission facilities ($207 and $206 related to Altus VIE)	673		670
Other ($4 and $3 related to Altus VIE)	1,124		1,140
Less: Accumulated depreciation, depletion, and amortization ($22 and $13 related to Altus VIE)	(33,889)		(34,810)
	8,113		8,819
OTHER ASSETS:
Equity method interests (Note 7) ($1,538 and $1,555 related to Altus VIE)	1,538		1,555
Decommissioning security for sold Gulf of Mexico properties (Note 12)	740		—
Deferred charges and other ($8 and $5 related to Altus VIE)	514		526
Note receivable from APA Corporation (Note 2)	1,352		—
	$	14,426	$	12,746
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable ($9 and $6 related to Altus VIE)	$	643	$	444
Note payable to APA Corporation	243		—
Current debt	215		2
Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)	937		862
	2,038		1,308
LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)	7,193		8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	169		215
Asset retirement obligation (Note 9) ($67 and $64 related to Altus VIE)	1,912		1,888
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	1,186		—
Other ($126 and $144 related to Altus VIE)	527		602
	3,794		2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)	635		608
EQUITY (DEFICIT):
Common stock, $0.625 par, 1,000 and 860,000,000 shares authorized, respectively, 1,000 and 418,429,375 shares issued, respectively	—		262
Paid-in capital	9,532		11,735
Accumulated deficit	(9,726)		(10,461)
Treasury stock, at cost, 0 and 40,946,745 shares, respectively	—		(3,189)
Accumulated other comprehensive income	15		14
DEFICIT ATTRIBUTABLE TO APA CORPORATION	(179)		(1,639)
Noncontrolling interest - Egypt	854		925
Noncontrolling interest - Altus	91		69
TOTAL EQUITY (DEFICIT)	766		(645)
	$	14,426	$	12,746

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

4

APACHE CORPORATION AND SUBSIDIARIES

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

(Unaudited)

	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		PARENT COMPANY DEFICIT		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Quarter Ended September 30, 2020
Balance at June 30, 2020	$	592	$	262	$	11,744	$	(10,467)	$	(3,189)	$	15	$	(1,635)	$	999	$	(636)
Net loss attributable to APA Corporation	—		—		—		(4)		—		—		(4)		—		(4)
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		24		24
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		2		2
Net income attributable to Altus Preferred Unit holders	19		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(11)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(21)		(21)
Common dividends declared ($0.025 per share)	—		—		(10)		—		—		—		(10)		—		(10)
Other	—		—		7		—		—		1		8		—		8
Balance at September 30, 2020	$	600	$	262	$	11,741	$	(10,471)	$	(3,189)	$	16	$	(1,641)	$	1,004	$	(637)
For the Quarter Ended September 30, 2021
Balance at June 30, 2021	$	617	$	—	$	9,535	$	(9,642)	$	—	$	15	$	(92)	$	1,040	$	948
Net loss attributable to APA Corporation	—		—		—		(83)		—		—		(83)		—		(83)
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		49		49
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		4		4
Net income attributable to Altus Preferred Unit limited partners	30		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(143)		(143)
Distributions to APA Corporation	—		—		(9)		—		—		—		(9)		—		(9)
Other	—		—		6		(1)		—		—		5		(5)		—
Balance at September 30, 2021	$	635	$	—	$	9,532	$	(9,726)	$	—	$	15	$	(179)	$	945	$	766

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

5

APACHE CORPORATION AND SUBSIDIARIES

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

(Unaudited)

	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		PARENT COMPANY DEFICIT		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Nine Months Ended September 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 APA Corporation	—		—		—		(4,870)		—		—		(4,870)		—		(4,870)
Net loss attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(138)		(138)
Net loss attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		(7)		(7)
Net income attributable to Altus Preferred Unit holders	56		—		—		—		—		—		—		—		—
Distributions to Altus Preferred Unit limited partners	(11)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(61)		(61)
Common dividends declared ($0.075 per share)	—		—		(29)		—		—		—		(29)		—		(29)
Other	—		1		1		—		1		—		3		—		3
Balance at September 30, 2020	$	600	$	262	$	11,741	$	(10,471)	$	(3,189)	$	16	$	(1,641)	$	1,004	$	(637)
For the Nine Months Ended September 30, 2021
Balance at December 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)
Net income attributable to APA Corporation	—		—		—		653		—		—		653		—		653
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		132		132
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		32		32
Net income attributable to Altus Preferred Unit limited partners	73		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	(34)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(203)		(203)
Distributions to APA Corporation	—		—		(19)		—		—		—		(19)		—		(19)
Common dividends declared ($0.1125 per share)	—		—		(9)		—		—		—		(9)		—		(9)
APA Corporation share exchange	—		(262)		(2,927)		—		3,189		—		—		—		—
Holding Company Reorganization	—		—		757		82		—		—		839		—		839
Other	—		—		(5)		—		—		1		(4)		(10)		(14)
Balance at September 30, 2021	$	635	$	—	$	9,532	$	(9,726)	$	—	$	15	$	(179)	$	945	$	766

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

6

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by Apache Corporation (Apache 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 recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, which contains a summary of the Company’s significant accounting policies and other disclosures.

On January 4, 2021, Apache announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache became a direct, wholly-owned subsidiary of APA Corporation (APA), and all of Apache’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 pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache 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 making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.

1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2021, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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 Apache 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 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, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualifies as a variable interest entity under GAAP, for which Apache consolidates because a wholly-owned subsidiary of Apache has a controlling financial interest and was determined to be the primary beneficiary.

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 the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 7—Equity Method Interests for further detail.

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Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities require management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of 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 3—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 9—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 12—Commitments and Contingencies), the estimate of income taxes (refer to Note 11—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 fair value measurements. 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 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, and Note 13—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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Oil and gas proved property	$	—	$	—	$	—	$	4,319
Gathering, processing, and transmission facilities	—		—		—		68
Goodwill	—		—		—		87
Inventory and other	18		—		18		18
Total Impairments	$	18	$	—	$	18	$	4,492

During the third quarter and first nine months of 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

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During the first nine months of 2020, the Company recognized total asset impairments of $4.5 billion in connection 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 its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment. The Company recognized proved property impairments of $3.9 billion, $374 million, and $7 million in the U.S., Egypt, and North Sea, respectively, to reduce the carrying value of its oil and gas properties to the estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million 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, the Company separately recognized impairments of $13 million for the early termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.

The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting segment. Reductions in the estimated net present value of expected future cash flows from oil and gas properties resulted in fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.

Accounts Receivable from / Accounts Payable to APA

Accounts receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Generally, cash in this amount will be transferred to Apache or paid to APA in subsequent periods, after current period transactions are processed and net results of operations are determined. However, from time to time, Apache may estimate and transfer the cash settlement amount in the month the transactions are processed in order to minimize affiliate working capital balances. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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.

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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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Proved Properties:
U.S.	$	—	$	—	$	—	$	3,938
Egypt	—		—		—		374
North Sea	—		—		—		7
Total proved properties	$	—	$	—	$	—	$	4,319
Unproved Properties:
U.S.	$	2	$	34	$	19	$	80
Egypt	2		2		6		6
North Sea	1		—		1		—
Total unproved properties	$	5	$	36	$	26	$	86

Proved properties impaired during the first nine months of 2020 had an aggregate fair value of $1.9 billion.

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 3—Acquisitions and Divestitures for more detail.

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Gathering, Processing, and Transmission Facilities

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

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

The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2021 and 2020.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, were $1.1 billion and $670 million as of September 30, 2021 and December 31, 2020, respectively. Refer to Note 15—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.

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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Production revenues from customers	$	1,562	$	1,002	$	4,294	$	2,905
Production revenues from non-customers	123		44		336		74
Total production revenues	$	1,685	$	1,046	$	4,630	$	2,979

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

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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 and $8 million of reorganization costs were incurred in the third quarter and first nine months of 2021, respectively, primarily related to ongoing consulting and separation activities in the Company’s international operations.

The Company recorded $7 million and $44 million of TRS costs during the third quarter and first nine months of 2020, respectively. TRS costs incurred in the first nine months of 2020 relate to $41 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs.

2.    TRANSACTIONS WITH PARENT AFFILIATE

The Company completed the Holding Company Reorganization on March 1, 2021 and sold to APA all of the equity in the three Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The reorganization gave rise to a note payable by APA to Apache. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the three subsidiaries sold by Apache to APA.

The Company recognized interest income of approximately $15 million and $35 million on this note during the third quarter and first nine months of 2021, respectively, which is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2021 to PIK pursuant to the note.

The Company accounted for the divestiture of its subsidiaries as a transfer to an affiliate entity under common control and no longer consolidates the subsidiaries for periods subsequent to the Holding Company Reorganization. The carrying value of the net assets transferred was $483 million, which included approximately $292 million of Cash and cash equivalents, $163 million of Oil and gas properties, and working capital items. The Company continues to hold its existing assets in the U.S., Egypt, and U.K., and its current economic interests in ALTM and its subsidiary, Altus Midstream LP.

The Company continues to provide administrative and support operations to APA related to activities performed for the Suriname and Dominican Republic subsidiaries. The Company is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company in connection with its role as service provider. All reimbursements are based on actual costs incurred and no market premium is applied by the Company to APA. The Company incurred $5 million and $12 million in reimbursable corporate overhead charges for the third quarter and first nine months of 2021, respectively.

In August 2021, Apache entered into an promissory note with APA under which Apache may borrow up to $250 million from APA at APA’s discretion. The note has a term of one year, maturing on August 4, 2022, and bears interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of September 30, 2021, there was $243 million outstanding under this note, which is reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet.

3.    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 $174 million and the assumption of asset retirement obligations of $44 million. The Company has recognized a gain of approximately $63 million in connection with the sale. The transaction is subject to normal post-closing adjustments.

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

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

On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline.

As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews. Upon closing of the transaction, management will reevaluate whether Apache has a controlling financial interest and is the primary beneficiary of ALTM such that consolidation would continue to be required under the VIE model.

2020 Activity

During the first nine months of 2020, the Company completed non-core asset and leasehold sales, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $53 million. The Company recognized a gain of approximately $5 million upon closing of these transactions.

The Company also completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $3 million.

4.    CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $54 million and $197 million as of September 30, 2021 and December 31, 2020, respectively. The decrease is primarily attributable to the completion of the Holding Company Reorganization in which the Company sold its interests in Suriname, including approximately $135 million of exploratory well costs as of December 31, 2020, to APA. Refer to Note 2—Transactions with Parent Affiliate for more detail. The remaining exploratory well costs relate to North Sea offshore wells and Egypt onshore wells where additional drilling activity was offset by dry hole write-offs during the period.

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.

5.    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. The Company manages variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production by utilizing various types of financial instruments. The Company has elected not to designate any of its derivative contracts as cash flow hedges.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2021, the Company had derivative positions with 11 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.

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Derivative Instruments

Commodity Derivative Instruments

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

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls	Weighted Average Fixed Price
October—December 2021	NYMEX WTI	1,012	$58.59
October—December 2021	Dated Brent	828	$61.44

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

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

As of September 30, 2021, the Company had the following open natural gas financial basis swap contracts:

		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2021	NYMEX Henry Hub/IF Waha	11,050	$(0.42)	—	—
October—December 2021	NYMEX Henry Hub/IF HSC	—	—	11,050	$(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

Embedded Derivatives

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP, a subsidiary of ALTM, issued and sold Series A Cumulative Redeemable Preferred Units (Preferred Units). Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, refer to “Fair Value Measurements” below and Note 13—Redeemable Noncontrolling Interest - Altus.

Pipeline Capacity Embedded Derivatives

During the fourth quarter of 2019 and first quarter of 2020, the Company entered into an agreement to assign a portion of its contracted capacity under an existing transportation agreement to a third party. Embedded in this agreement is an arrangement under which the Company has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. This feature requires bifurcation and measurement of the change in market value for each period. Unrealized gains or losses in the fair value of this feature are recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received are deferred and reflected in income over the original tenure of the host contract.

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Fair Value Measurements

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
September 30, 2021
Liabilities:
Commodity derivative instruments	—		32		—		32		—		32
Pipeline capacity embedded derivatives	—		47		—		47		—		47
Preferred Units embedded derivative	—		—		120		120		—		120
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivative	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

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 the income approach, a Level 3 fair value measurement, and 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 feature, and anticipated dividend yields of the Preferred Units. As of the September 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 September 30, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	120	Option Model	Altus’ Imputed Interest Rate	5.53-11.54%
				Interest Rate Volatility	38.03%

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of September 30, 2021, while a one percent decrease would lead to a similar decrease in value as of September 30, 2021. The assumed expected timing until exercise of the exchange option as of September 30, 2021 was 4.70 years.

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Derivative Activity Recorded in the Consolidated Balance Sheet

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

	September 30, 2021		December 31, 2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	31	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	168		192
Total derivative liabilities	$	199	$	192

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Realized:
Commodity derivative instruments	$	(37)	$	(83)	$	63	$	(119)
Foreign currency derivative instruments	—		—		—		(1)
Realized gain (loss), net	(37)		(83)		63		(120)
Unrealized:
Commodity derivative instruments	29		91		(43)		(3)
Pipeline capacity embedded derivatives	3		8		6		(62)
Foreign currency derivative instruments	—		3		—		(1)
Preferred units embedded derivative	5		(3)		19		(76)
Unrealized loss, net	37		99		(18)		(142)
Derivative instrument gains (losses), net	$	—	$	16	$	45	$	(262)

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

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

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6.    OTHER CURRENT ASSETS

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

	September 30, 2021		December 31, 2020
	(In millions)
Inventories	$	441	$	492
Drilling advances	102		113
Prepaid assets and other	56		71
Total Other current assets	$	599	$	676

7.    EQUITY METHOD INTERESTS

As of September 30, 2021 and December 31, 2020, the Company, through its ownership of Altus, had the following equity method interests in four Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentages held by the Company and associated carrying values for each entity:

	Interest	September 30, 2021		December 31, 2020
		(In millions)
Gulf Coast Express Pipeline, LLC	16.0%	$	277	$	284
EPIC Crude Holdings, LP	15.0%	165		176
Permian Highway Pipeline, LLC	26.7%	632		615
Shin Oak Pipeline (Breviloba, LLC)	33.0%	464		480
Total Altus equity method interests		$	1,538	$	1,555

As of September 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.

The following table presents the activity in Altus’ equity method interests for the nine months ended September 30, 2021:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2020	$	284	$	176	$	615	$	480	$	1,555
Capital contributions	—		2		25		—		27
Distributions	(37)		—		(52)		(39)		(128)
Equity income (loss), net	30		(14)		44		23		83
Accumulated other comprehensive income	—		1		—		—		1
Balance at September 30, 2021	$	277	$	165	$	632	$	464	$	1,538

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 Nine Months Ended September 30,
	2021		2020
	(In millions)
Operating revenues	$	812	$	531
Operating income	401		267
Net income	340		217
Other comprehensive income (loss)	4		(1)

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8.    OTHER CURRENT LIABILITIES

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

	September 30, 2021		December 31, 2020
	(In millions)
Accrued operating expenses	$	135	$	91
Accrued exploration and development	167		167
Accrued compensation and benefits	180		170
Accrued interest	92		140
Accrued income taxes	54		25
Current asset retirement obligation	56		56
Current operating lease liability	87		116
Current portion of derivatives at fair value	31		—
Other	135		97
Total Other current liabilities	$	937	$	862

9.    ASSET RETIREMENT OBLIGATION

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

	September 30, 2021
	(In millions)
Asset retirement obligation, December 31, 2020	$	1,944
Liabilities incurred	3
Liabilities settled	(20)
Liabilities divested	(44)
Accretion expense	85
Asset retirement obligation, September 30, 2021	1,968
Less current portion	(56)
Asset retirement obligation, long-term	$	1,912

10.    DEBT AND FINANCING COSTS

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

	September 30, 2021		December 31, 2020
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	6,344	$	8,052
Altus credit facility(2)	657		624
Apache credit facility(2)	440		150
Finance lease obligations	36		38
Unamortized discount	(29)		(35)
Debt issuance costs	(40)		(57)
Total debt	7,408		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,193	$	8,770

(1)    The fair values of the Company’s notes and debentures were $7.0 billion and $8.5 billion as of September 30, 2021 and December 31, 2020, respectively.

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

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

As of September 30, 2021, current debt included $213 million, net of discount, 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.

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During the quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes and accepted for purchase $1.7 billion aggregate principal amount of certain notes. Apache paid holders an aggregate $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $98 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During the nine months ended September 30, 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

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

In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2021. The facility is for general corporate purposes. As of September 30, 2021, there were $440 million of borrowings and an aggregate £478 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 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 the Company’s credit rating from BBB to BB+ on March 26, 2020.

There were no borrowings outstanding under the Company’s commercial paper program as of September 30, 2021 and December 31, 2020. The Company did not use its commercial paper program during the first six months of 2021 and terminated the program during the third quarter of 2021.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2021, there were no borrowings and £118 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2020, there were no borrowings and £34 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 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 September 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 Apache, APA Corporation, or any of its subsidiaries.

Financing Costs, Net

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	102	$	113	$	324	$	327
Amortization of debt issuance costs	1		2		6		6
Capitalized interest	—		(3)		—		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Interest income from APA Corporation, net	(15)		—		(35)		—
Financing costs, net	$	192	$	99	$	393	$	168

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11.    INCOME TAXES

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

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

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.

12.    COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2021, the Company has an accrued liability of approximately $68 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matter has occurred since the filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

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 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.

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Starting in November of 2013 and continuing into 2021, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

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

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested 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, four ex-employees of Apache Canada 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 three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases have been sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state 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.

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

Castex Lawsuit

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

Oklahoma Class Actions

The Company is a party to two purported class actions 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 of approximately $200 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. The amount 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.

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.

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. The defendants believe the plaintiff’s claims lack merit and intend to vigorously defend this lawsuit.

Environmental Matters

As of September 30, 2021, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

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

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

The Company is not aware of any environmental claims existing as of September 30, 2021 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 Obligation to Decommission Sold Properties

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

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

In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund its decommissioning obligations on certain of the Legacy GOM Assets that GOM Shelf is currently required to perform. 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 Properties 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.

As and when Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache, Apache will 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, Apache may be forced to effectively use its available cash to fund the deficit.

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As of September 30, 2021, Apache estimates that its potential liability to fund decommissioning of GOM Legacy 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, in the third quarter of 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning contingency for sold Gulf of Mexico properties” in the Company’s consolidated balance sheet. The Company also recorded a $740 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 GOM Legacy Assets under the caption “Decommissioning security for sold Gulf of Mexico properties”. A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. 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 natural gas liquids could further impact Apache’s estimate of its contingent liability to decommission GOM Legacy Assets.

13.    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 carrying amount of the Preferred Units are recorded as “Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

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

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Activity related to the Preferred Units is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions to Altus Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream LP net income	N/A	76
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(34)
Dividends payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	60
Accreted value adjustment	N/A	13
Redeemable noncontrolling interest — Preferred Unit at: September 30, 2021	660,694	635
Preferred Units embedded derivative(2)		120
		$	755

(1)    The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of September 30, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of September 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 $730 million.

(2)    Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 5—Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.

N/A - not applicable.

14.    CAPITAL STOCK AND EQUITY

Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization, Apache recorded various intercompany activities during the first quarter ended March 31, 2021, as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail.

Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache.

Net Income (Loss) per Common Share

Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly-owned subsidiary of APA.

Common Stock Dividends

During the third quarter and the first nine months ended September 30, 2020, the Company paid $9 million and $113 million, respectively, in dividends on its common stock. During the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.

During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the nine months ended September 30, 2021, the Company paid $19 million in capital distributions to its parent, APA, which is reflected as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

25

15.    BUSINESS SEGMENT INFORMATION

As of September 30, 2021, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company’s Midstream business is operated by Altus Midstream Company, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Quarter Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	465	$	233	$	484	$	—	$	—	$	1,182
Natural gas revenues	63		42		188		—		—		293
Natural gas liquids revenues	2		6		202		—		—		210
Oil, natural gas, and natural gas liquids production revenues	530		281		874		—		—		1,685
Purchased oil and gas sales	—		—		374		—		—		374
Midstream service affiliate revenues	—		—		—		35		(35)		—
	530		281		1,248		35		(35)		2,059
Operating Expenses:
Lease operating expenses	117		101		98		—		—		316
Gathering, processing, and transmission	4		8		82		9		(35)		68
Purchased oil and gas costs	—		—		396		—		—		396
Taxes other than income	—		—		52		2		—		54
Exploration	14		4		3		—		—		21
Depreciation, depletion, and amortization	128		61		143		3		—		335
Asset retirement obligation accretion	—		20		8		1		—		29
Impairments	—		18		—		—		—		18
	263		212		782		15		(35)		1,237
Operating Income(1)	$	267	$	69	$	466	$	20	$	—	822
Other Income (Expense):
Loss on offshore decommissioning contingency											(446)
Loss on divestitures, net											(2)
Other, net											40
General and administrative											(64)
Transaction, reorganization, and separation											(4)
Financing costs, net											(192)
Income Before Income Taxes											$	154

26

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Nine Months Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	1,299	$	690	$	1,325	$	—	$	—	$	3,314
Natural gas revenues	198		100		533		—		—		831
Natural gas liquids revenues	6		16		463		—		—		485
Oil, natural gas, and natural gas liquids production revenues	1,503		806		2,321		—		—		4,630
Purchased oil and gas sales	—		—		1,050		6		—		1,056
Midstream service affiliate revenues	—		—		—		99		(99)		—
	1,503		806		3,371		105		(99)		5,686
Operating Expenses:
Lease operating expenses	335		274		283		—		(1)		891
Gathering, processing, and transmission	8		28		225		24		(98)		187
Purchased oil and gas costs	—		—		1,147		5		—		1,152
Taxes other than income	—		—		139		10		—		149
Exploration	36		27		21		—		2		86
Depreciation, depletion, and amortization	395		208		416		9		—		1,028
Asset retirement obligation accretion	—		59		23		3		—		85
Impairments	—		18		—		—		—		18
	774		614		2,254		51		(97)		3,596
Operating Income (Loss)(1)	$	729	$	192	$	1,117	$	54	$	(2)	2,090
Other Income (Expense):
Derivative instrument gains, net											45
Loss on offshore decommissioning contingency											(446)
Gain on divestitures, net											65
Other, net											175
General and administrative											(226)
Transaction, reorganization, and separation											(8)
Financing costs, net											(393)
Income Before Income Taxes											$	1,302
Total Assets(2)	$	2,887	$	2,080	$	7,606	$	1,853	$	—	$	14,426

27

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Quarter Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	303	$	179	$	303	$	—	$	—	$	785
Natural gas revenues	74		13		77		—		—		164
Natural gas liquids revenues	2		5		90		—		—		97
Oil, natural gas, and natural gas liquids production revenues	379		197		470		—		—		1,046
Purchased oil and gas sales	—		—		73		1		—		74
Midstream service affiliate revenues	—		—		—		39		(39)		—
	379		197		543		40		(39)		1,120
Operating Expenses:
Lease operating expenses	102		79		79		—		(1)		259
Gathering, processing, and transmission	8		10		74		9		(38)		63
Purchased oil and gas costs	—		—		74		1		—		75
Taxes other than income	—		—		30		4		—		34
Exploration	10		10		34		—		4		58
Depreciation, depletion, and amortization	144		90		161		3		—		398
Asset retirement obligation accretion	—		18		8		1		—		27
	264		207		460		18		(35)		914
Operating Income (Loss)(1)	$	115	$	(10)	$	83	$	22	$	(4)	206
Other Income (Expense):
Derivative instrument gains, net											16
Loss on divestitures, net											(1)
Other, net											9
General and administrative											(52)
Transaction, reorganization, and separation											(7)
Financing costs, net											(99)
Income Before Income Taxes											$	72

28

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Nine Months Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	823	$	578	$	929	$	—	$	—	$	2,330
Natural gas revenues	209		39		169		—		—		417
Natural gas liquids revenues	6		15		211		—		—		232
Oil, natural gas, and natural gas liquids production revenues	1,038		632		1,309		—		—		2,979
Purchased oil and gas sales	—		—		235		2		—		237
Midstream service affiliate revenues	—		—		—		111		(111)		—
	1,038		632		1,544		113		(111)		3,216
Operating Expenses:
Lease operating expenses	312		234		313		—		(1)		858
Gathering, processing, and transmission	31		37		219		29		(110)		206
Purchased oil and gas costs	—		—		205		2		—		207
Taxes other than income	—		—		79		11		—		90
Exploration	51		26		100		—		10		187
Depreciation, depletion, and amortization	463		278		632		9		—		1,382
Asset retirement obligation accretion	—		54		24		3		—		81
Impairments	529		7		3,956		—		—		4,492
	1,386		636		5,528		54		(101)		7,503
Operating Income (Loss)(1)	$	(348)	$	(4)	$	(3,984)	$	59	$	(10)	(4,287)
Other Income (Expense):
Derivative instrument losses, net											(262)
Gain on divestitures											24
Other, net											41
General and administrative											(214)
Transaction, reorganization, and separation											(44)
Financing costs, net											(168)
Loss Before Income Taxes											$	(4,910)
Total Assets(2)	$	3,052	$	2,238	$	5,708	$	1,741	$	136	$	12,875

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

Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $19 million, $6 million, and $19 million, respectively, for the first nine months of 2021.

Operating loss of U.S. and Egypt includes leasehold and other asset impairments of $34 million and $2 million, respectively, for the third quarter of 2020.

Operating loss of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $4.0 billion, $535 million, and $7 million, respectively, for the first nine months of 2020.

(2)    Intercompany balances are excluded from total assets.

(3)    Includes noncontrolling interests in Egypt and Altus.

(4)    On March 1, 2021, the Company sold its Suriname and Dominican Republic operations to APA. Refer to Note 2—Transactions with Parent Affiliate for more details on the transaction.

29

ITEM 2.    MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

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

On January 4, 2021, the Company announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, the Company became a direct, wholly-owned subsidiary of APA Corporation (APA), and all of the Company’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company 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 making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.

Overview

Apache, a direct, wholly-owned subsidiary of 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). The Company’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

The Company’s mission is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of 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 coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the commodity and financial markets during 2020 and 2021 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; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its capital program that can be directed on a priority basis to debt reduction. 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.

In the third quarter of 2021, the Company reported a net loss of $83 million compared to a net loss of $4 million in the third quarter of 2020. The increase in net loss compared to the prior-year period is primarily the result of a non-cash $446 million loss on previously sold Gulf of Mexico properties, which represents the Company’s estimate of decommissioning Apache may be required to perform or pay for on assets sold to Fieldwood in 2013 in excess of securities available to the Company to recover costs incurred with respect to such decommissioning. For additional details of this loss, please refer to Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q. Absent this charge, the quarter benefited from significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic negatively affected 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 2020. Daily production decreased 13 percent from an average of 445 Mboe/d in the third quarter of 2020 to an average of 389 Mboe/d in the third quarter of 2021.

The Company generated $2.4 billion of cash from operating activities during the first nine months of 2021, a 172 percent increase from the first nine months of 2020, driven by higher commodity prices and associated revenues. Since year-end the Company reduced its outstanding debt by $1.1 billion, and it had $348 million of cash at the end of the third quarter of 2021.

Following this progress and considering the ongoing constructive price environment, the Company has adjusted its cash allocation approach. The capital investment program will be increased to a level intended to sustain or slightly grow global production volumes. This will be primarily accomplished through a gradual ramp in activity over the next few quarters, primarily in Egypt, but also in the U.S. Onshore.

30

Operational Highlights

Key operational highlights for the quarter include:

United States

•Equivalent production from the Company’s U.S. assets accounted for 61 percent of its total production during the third quarter of 2021. After halting all drilling and completion activity for most of 2020, in early 2021 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. During the third quarter, the Company placed nine wells online in the Permian Basin. One additional well was drilled in the Austin Chalk, where the results are continuing to be evaluated, and a drilling rig was recently added to advance the characterization of the Company’s acreage position in the play.

•On October 11, 2021, APA announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals, three months ahead of schedule.

•On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. Upon closing of the transaction, APA will own approximately 20 percent of the issued and outstanding common stock of the combined entity. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews.

International

•In May 2021, 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 the 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.

•In Egypt, the Company averaged 8 drilling rigs and completed 12 wells during the third quarter of 2021. Third-quarter gross equivalent production in the Company’s Egypt assets decreased 15 percent from the third quarter of 2020, given reduced drilling activity over the preceding year. 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 agreement referenced above, the Company expects to further increase drilling and workover activity.

•The Company averaged two rigs in the North Sea during the third quarter of 2021. Production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages during the first nine months of the year.

31

Results of Operations

Oil and Gas 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 September 30,								For the Nine Months Ended September 30,
	2021				2020				2021				2020
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	484	41	%	$	303	39	%	$	1,325	40	%	$	929	40	%
Egypt(1)	465		39	%	303		38	%	1,299		39	%	823		35	%
North Sea	233		20	%	179		23	%	690		21	%	578		25	%
Total(1)	$	1,182	100	%	$	785	100	%	$	3,314	100	%	$	2,330	100	%
Natural Gas Revenues:
United States	$	188	64	%	$	77	47	%	$	533	64	%	$	169	41	%
Egypt(1)	63		22	%	74		45	%	198		24	%	209		50	%
North Sea	42		14	%	13		8	%	100		12	%	39		9	%
Total(1)	$	293	100	%	$	164	100	%	$	831	100	%	$	417	100	%
NGL Revenues:
United States	$	202	96	%	$	90	93	%	$	463	95	%	$	211	91	%
Egypt(1)	2		1	%	2		2	%	6		1	%	6		3	%
North Sea	6		3	%	5		5	%	16		4	%	15		6	%
Total(1)	$	210	100	%	$	97	100	%	$	485	100	%	$	232	100	%
Oil and Gas Revenues:
United States	$	874	52	%	$	470	45	%	$	2,321	50	%	$	1,309	44	%
Egypt(1)	530		31	%	379		36	%	1,503		33	%	1,038		35	%
North Sea	281		17	%	197		19	%	806		17	%	632		21	%
Total(1)	$	1,685	100	%	$	1,046	100	%	$	4,630	100	%	$	2,979	100	%

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

32

Production

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

	For the Quarter Ended September 30,			For the Nine Months Ended, September 30,
	2021	Increase (Decrease)	2020	2021	Increase (Decrease)	2020
Oil Volume (b/d)
United States	75,526	(9)%	83,178	75,384	(19)%	93,051
Egypt(1)(2)	69,830	(12)%	79,194	71,052	(8)%	77,410
North Sea	33,783	(31)%	48,755	36,398	(28)%	50,339
Total	179,139	(15)%	211,127	182,834	(17)%	220,800
Natural Gas Volume (Mcf/d)
United States	546,058	(9)%	597,686	531,695	(7)%	571,325
Egypt(1)(2)	243,294	(15)%	286,744	259,108	(5)%	273,676
North Sea	33,752	(36)%	53,137	40,061	(31)%	57,659
Total	823,104	(12)%	937,567	830,864	(8)%	902,660
NGL Volume (b/d)
United States	70,962	(6)%	75,266	65,805	(13)%	75,468
Egypt(1)(2)	496	(19)%	611	544	(33)%	812
North Sea	1,200	(39)%	1,976	1,220	(37)%	1,948
Total	72,658	(7)%	77,853	67,569	(14)%	78,228
BOE per day(3)
United States	237,498	(8)%	258,058	229,805	(13)%	263,740
Egypt(1)(2)	110,875	(13)%	127,595	114,780	(7)%	123,834
North Sea(4)	40,608	(32)%	59,588	44,295	(28)%	61,897
Total	388,981	(13)%	445,241	388,880	(13)%	449,471

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

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2021	2020	2021	2020
Oil (b/d)	134,128	159,941	134,976	171,778
Natural Gas (Mcf/d)	564,354	649,566	581,859	648,995
NGL (b/d)	776	1,175	846	1,534

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

	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	2021	2020	2021	2020
Oil (b/d)	23,309	26,459	23,716	25,891
Natural Gas (Mcf/d)	81,309	95,776	86,564	91,374
NGL (b/d)	165	204	181	271

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

(4)    Average sales volumes from the North Sea for the third quarter of 2021 and 2020 were 40,581 boe/d and 57,099 boe/d, respectively, and 45,637 boe/d and 61,771 boe/d for the first nine months of 2021 and 2020, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

33

Pricing

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

	For the Quarter Ended September 30,					For the Nine Months Ended, September 30,
	2021		Increase (Decrease)	2020		2021		Increase (Decrease)	2020
Average Oil Price - Per barrel
United States	$	69.69	76%	$	39.60	$	64.38	77%	$	36.45
Egypt	72.37		74%	41.51		66.97		73%	38.79
North Sea	74.94		78%	42.10		66.93		59%	41.99
Total	71.72		75%	40.88		65.90		71%	38.53
Average Natural Gas Price - Per Mcf
United States	$	3.75	168%	$	1.40	$	3.67	240%	$	1.08
Egypt	2.82		—%	2.82		2.80		—%	2.79
North Sea	13.40		419%	2.58		9.13		271%	2.46
Total	3.87		104%	1.90		3.66		117%	1.69
Average NGL Price - Per barrel
United States	$	30.85	136%	$	13.06	$	25.75	152%	$	10.20
Egypt	52.02		101%	25.88		44.73		70%	26.24
North Sea	56.64		109%	27.08		48.32		69%	28.54
Total	31.42		133%	13.51		26.32		143%	10.83

Third-Quarter 2021 compared to Third-Quarter 2020

Crude Oil Crude oil revenues for the third quarter of 2021 totaled $1.2 billion, a $397 million increase from the comparative 2020 quarter. A 75 percent increase in average realized prices increased third-quarter 2021 oil revenues by $592 million compared to the prior-year quarter, while 15 percent lower average daily production decreased revenues by $195 million. Crude oil revenues accounted for 70 percent of total oil and gas production revenues and 46 percent of worldwide production in the third quarter of 2021. The Company’s worldwide oil production decreased 32.0 Mb/d to 179.1 Mb/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of natural production decline across all countries and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Gas revenues for the third quarter of 2021 totaled $293 million, a $129 million increase from the comparative 2020 quarter. A 104 percent increase in average realized prices increased third-quarter 2021 natural gas revenues by $170 million compared to the prior-year quarter, while 12 percent lower average daily production decreased revenues by $41 million. Natural gas revenues accounted for 17 percent of total oil and gas production revenues and 35 percent of worldwide production during the third quarter of 2021. The Company’s worldwide natural gas production decreased 114.5 MMcf/d to 823 MMcf/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries and extended operational downtime in the North Sea, offset by increased completion activity in the U.S.

NGL NGL revenues for the third quarter of 2021 totaled $210 million, a $113 million increase from the comparative 2020 quarter. A 133 percent increase in average realized prices increased third-quarter 2021 NGL revenues by $128 million compared to the prior-year quarter, while 7 percent lower average daily production decreased revenues by $15 million. NGL revenues accounted for 13 percent of total oil and gas production revenues and 19 percent of worldwide production during the third quarter of 2021. The Company’s worldwide NGL production decreased 5.2 Mb/d to 72.7 Mb/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries.

34

Year-to-Date 2021 compared to Year-to-Date 2020

Crude Oil Crude oil revenues for the first nine months of 2021 totaled $3.3 billion, a $1.0 billion increase from the comparative 2020 period. A 71 percent increase in average realized prices increased oil revenues for the 2021 period by $1.7 billion compared to the prior-year period, while 17 percent lower average daily production decreased revenues by $671 million compared to the prior-year period. Crude oil revenues accounted for 72 percent of total oil and gas production revenues and 47 percent of worldwide production for the first nine months of 2021. Crude oil prices realized during the first nine months of 2021 averaged $65.90 per barrel, compared to $38.53 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 38.0 Mb/d to 182.8 Mb/d in the first nine months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Gas revenues for the first nine months of 2021 totaled $831 million, a $414 million increase from the comparative 2020 period. A 117 percent increase in average realized prices increased natural gas revenues for the 2021 period by $489 million compared to the prior-year period, while 8 percent lower average daily production decreased revenues by $75 million compared to the prior-year period. Natural gas revenues accounted for 18 percent of total oil and gas production revenues and 36 percent of worldwide production for the first nine months of 2021. Natural gas prices realized during the first nine months of 2021 averaged $3.66 per Mcf, compared to $1.69 per Mcf in the comparative prior-year period. Gas prices for the U.S. during the first nine 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 72 MMcf/d to 831 MMcf/d in the first nine months of 2021 compared to the prior-year period, primarily a result of 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.

NGL NGL revenues for the first nine months of 2021 totaled $485 million, a $253 million increase from the comparative 2020 period. A 143 percent increase in average realized prices increased NGL revenues for the 2021 period by $332 million compared to the prior-year period, while 14 percent lower average daily production decreased revenues by $79 million compared to the prior-year period. NGL revenues accounted for 10 percent of total oil and gas production revenues and 17 percent of worldwide production for the first nine months of 2021. NGL prices realized during the first nine months of 2021 averaged $26.32 per barrel, compared to $10.83 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased 10.7 Mb/d to 67.6 Mb/d in the first nine months of 2021 compared to the prior-year period, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.

Altus Midstream Revenues

Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $35 million and $39 million during the third quarters of 2021 and 2020, respectively, and $99 million and $111 million during the first nine months of 2021 and 2020, respectively. These affiliated revenues are eliminated upon consolidation. Changes in revenue compared to the prior periods were primarily driven by lower 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 $374 million and $74 million during the third quarters of 2021 and 2020, respectively, and $1.1 billion and $237 million during the first nine months of 2021 and 2020, respectively. Purchased oil and gas sales were offset by associated purchase costs of $396 million and $75 million during the third quarters of 2021 and 2020, respectively, and $1.2 billion and $207 million during the first nine months of 2021 and 2020, respectively. When compared to the prior-year periods, gross purchased oil and gas sales values and the associated net losses in the third quarter and first nine 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 during the month of February due to Winter Storm Uri in Texas.

35

Operating Expenses

The Company’s operating expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Lease operating expenses	$	316	$	259	$	891	$	858
Gathering, processing, and transmission	68		63		187		206
Purchased oil and gas costs	396		75		1,152		207
Taxes other than income	54		34		149		90
Exploration	21		58		86		187
General and administrative	64		52		226		214
Transaction, reorganization, and separation	4		7		8		44
Depreciation, depletion, and amortization:
Oil and gas property and equipment	306		366		940		1,284
Gathering, processing, and transmission assets	18		19		56		58
Other assets	11		13		32		40
Asset retirement obligation accretion	29		27		85		81
Impairments	18		—		18		4,492
Financing costs, net	192		99		393		168
Total Operating Expenses	$	1,497	$	1,072	$	4,223	$	7,929

Lease Operating Expenses (LOE)

LOE increased $57 million and $33 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 39 percent and 20 percent in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The increase was driven by higher turnaround 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 third quarter of 2021, and per-unit operating costs trending with higher oil and gas prices.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended, September 30,
	2021		2020		2021		2020
	(In millions)
Third-party processing and transmission costs	$	59	$	54	$	163	$	177
Midstream service affiliate costs	35		38		98		110
Upstream processing and transmission costs	94		92		261		287
Midstream operating expenses	9		9		24		29
Intersegment eliminations	(35)		(38)		(98)		(110)
Total Gathering, processing, and transmission	$	68	$	63	$	187	$	206

GPT costs increased $5 million and decreased $19 million in the third quarter and the first nine months 2021, respectively, from the comparative prior-year periods. Third-party processing and transmission costs increased $5 million and decreased $14 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The increase in third-party costs for the third quarter of 2021 was primarily driven by an increase in average transportation rates during the quarter. The overall decrease in third-party costs for the first nine months of 2021 was primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $3 million and $12 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The overall decrease in the first nine months of 2021 was primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, remained flat in the third quarter of 2021 and decreased $5 million in the first nine months of 2021, compared to the respective prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.

36

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $396 million and $1.2 billion during the third quarter and the first nine months of 2021, respectively, compared to $75 million and $207 million during the third quarter and the first nine months of 2020, respectively. Purchased oil and gas costs were offset by associated purchase sales of $374 million and $1.1 billion during the third quarter and the first nine months of 2021, respectively, compared to $74 million and $237 million during the third quarter and the first nine months of 2020, respectively, as further discussed above.

Taxes Other Than Income

Taxes other than income increased $20 million and $59 million from the third quarter and the first nine months of 2020, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the same prior-year periods.

Exploration Expenses

The Company’s exploration expenses were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended, September 30,
	2021		2020		2021		2020
	(In millions)
Unproved leasehold impairments	$	5	$	36	$	26	$	86
Dry hole expense	6		5		31		52
Geological and geophysical expense	4		7		6		14
Exploration overhead and other	6		10		23		35
Total Exploration	$	21	$	58	$	86	$	187

Exploration expenses decreased $37 million and $101 million from the third quarter and the first nine months of 2020, respectively, primarily the result of higher unproved leasehold impairments during the prior-year periods, due to lower oil and gas prices in the comparative periods. For the first nine months of 2021, the Company also had lower overhead and dry hole expenses resulting from decreased exploration activities compared to the prior year.

General and Administrative (G&A) Expenses

G&A expenses increased $12 million from the third quarter and the first nine months of 2020, primarily driven by higher cash-based stock compensation expense resulting from an increase in APA’s stock price, partially offset by lower overhead driven by organizational redesign efforts during 2019 and 2020.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $3 million and $36 million from the third quarter and the first nine months of 2020, respectively, driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.

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

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties decreased $60 million and $344 million from the third quarter and the first nine months of 2020, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.45 per boe and $1.61 per boe from the third quarter and the first nine months of 2020, 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 third quarter and the first nine months of 2020.

37

Impairments

During the third quarter and first nine months of 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

The Company recognized $4.5 billion in asset impairments in connection with fair value assessments during the first nine months of 2020. During the first half 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 facilities 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.

Financing Costs, Net

The Company’s Financing costs were as follows:

	For the Quarter Ended September 30,				For the Nine Months Ended, September 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	102	$	113	$	324	$	327
Amortization of debt issuance costs	1		2		6		6
Capitalized interest	—		(3)		—		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Interest income from APA Corporation, net	(15)		—		(35)		—
Total Financing costs, net	$	192	$	99	$	393	$	168

Net financing costs increased $93 million and $225 million from the third quarter and the first nine months of 2020, respectively, primarily driven by a $105 million loss on extinguishment of debt recognized in the third quarter of 2021, and a $152 million gain on extinguishment of debt during the first nine months of 2020. This increase was partially offset by interest income from APA Corporation as a result of the note receivable from APA related to the Holding Company Reorganization. Refer to Note 2—Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q for further information.

Provision for Income Taxes

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

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

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.

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.

38

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect reported amounts. Estimations are considered critical accounting estimates based on, among other things, its 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 its 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 estimates. With the exception of the critical accounting estimate listed below, there have been no significant changes to the Company’s estimates and assumptions during the nine months ended September 30, 2021 and 2020.

Offshore Decommissioning Contingency

The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Obligation to Decommission Sold Properties” within Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q. Changes in significant assumptions impacting the Company’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 natural gas liquids could further impact Apache’s estimate of its contingent liability to decommission GOM Legacy Assets.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Omitted.

ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2021, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

39

PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Refer to Part I, Item 3—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 and Note 12—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 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, APA 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 APA Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021, June 30, 2021, and September 30, 2021 and Altus Midstream Company’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, June 30, 2021, and September 30, 2021.

40

ITEM 6.    EXHIBITS

2.1	–	Agreement and Plan of Merger, dated as of March 1, 2021, by and among Registrant, APA Corporation, 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. 001-4300).
3.1	–	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as attached as Annex A to the Certificate of Merger of APA Merger Sub, Inc. with and into Registrant, 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. 001-4300).
3.2	–	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated June 7, 2021, filed with the Secretary of State of the State of Delaware on June 10, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 14, 2021, SEC File No. 001-4300).
3.3	–	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 filed March 1, 2021, SEC File No. 001-4300).
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101	–	The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.SCH	–	Inline XBRL Taxonomy Schema Document.
*101.CAL	–	Inline XBRL Calculation Linkbase Document.
*101.DEF	–	Inline XBRL Definition Linkbase Document.
*101.LAB	–	Inline XBRL Label Linkbase Document.
*101.PRE	–	Inline XBRL Presentation Linkbase Document.
*104	–	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*    Filed herewith

41

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.

		APACHE CORPORATION
Dated:	November 4, 2021	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
Dated:	November 4, 2021	/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller
		(Principal Accounting Officer)

42

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

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

Date: November 4, 2021

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

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

Date: November 4, 2021

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending September 30, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

Date: November 4, 2021

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

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending September 30, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

Date: November 4, 2021

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

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	Sep. 30, 2021	Oct. 31, 2021
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Entity File Number	1-4300
Entity Registrant Name	APACHE CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0747868
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		1,000
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
Entity Central Index Key	0000006769
Current Fiscal Year End Date	--12-31

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STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
REVENUES AND OTHER:
Derivative instrument gains (losses), net	$ 0	$ 16	$ 45	$ (262)
Gain (loss) on divestitures, net	(2)	(1)	65	24
Loss on previously sold Gulf of Mexico properties	(446)	0	(446)	0
Other, net	40	9	175	41
Total revenues and other	1,651	1,144	5,525	3,019
OPERATING EXPENSES:
Lease operating expenses	316	259	891	858
Taxes other than income	54	34	149	90
Exploration	21	58	86	187
General and administrative	64	52	226	214
Transaction, reorganization, and separation	4	7	8	44
Depreciation, depletion, and amortization	335	398	1,028	1,382
Asset retirement obligation accretion	29	27	85	81
Impairments	18	0	18	4,492
Financing costs, net	192	99	393	168
Total operating expenses	1,497	1,072	4,223	7,929
NET INCOME (LOSS) BEFORE INCOME TAXES	154	72	1,302	(4,910)
Current income tax provision	183	58	463	120
Deferred income tax benefit	(29)	(27)	(51)	(71)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	0	41	890	(4,959)
Net income attributable to Altus Preferred Unit limited partners	30	19	73	56
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	(83)	(4)	653	(4,870)
Noncontrolling interests, Egypt
OPERATING EXPENSES:
Net income attributable to nonredeemable noncontrolling interest	49	24	132	(138)
Noncontrolling interests, Altus
OPERATING EXPENSES:
Net income attributable to nonredeemable noncontrolling interest	4	2	32	(7)
Oil and gas
REVENUES AND OTHER:
Total revenues	2,059	1,120	5,686	3,216
Oil and gas, excluding purchased
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	1,685	1,046	4,630	2,979
Production revenues from customers	1,562	1,002	4,294	2,905
OPERATING EXPENSES:
Cost of goods and services sold	68	63	187	206
Oil and gas, purchased
REVENUES AND OTHER:
Production revenues from customers	374	74	1,056	237
OPERATING EXPENSES:
Cost of goods and services sold	$ 396	$ 75	$ 1,152	$ 207

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STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$ 0	$ 41	$ 890	$ (4,959)
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Share of equity method interests other comprehensive income	0	1	1	0
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	0	42	891	(4,959)
Comprehensive income attributable to Altus Preferred Unit limited partners	30	19	73	56
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	(83)	(3)	654	(4,870)
Noncontrolling interests, Egypt
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Comprehensive income (loss) attributable to nonredeemable noncontrolling interest	49	24	132	(138)
Noncontrolling interests, Altus
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Comprehensive income (loss) attributable to nonredeemable noncontrolling interest	$ 4	$ 2	$ 32	$ (7)

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STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$ 890	$ (4,959)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses, net	18	142
Gain on divestitures, net	(65)	(24)
Exploratory dry hole expense and unproved leasehold impairments	57	138
Depreciation, depletion, and amortization	1,028	1,382
Asset retirement obligation accretion	85	81
Impairments	18	4,492
Deferred income tax benefit	(51)	(71)
Loss (gain) on extinguishment of debt	104	(152)
Loss on offshore decommissioning contingency	446	0
Other, net	(42)	45
Changes in operating assets and liabilities:
Receivables	(274)	202
Inventories	(19)	16
Drilling advances and other current assets	20	(5)
Deferred charges and other long-term assets	(46)	(12)
Accounts payable	195	(211)
Accounts payable to APA Corporation	33	0
Accrued expenses	29	(211)
Deferred credits and noncurrent liabilities	(8)	37
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,418	890
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(673)	(1,075)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(2)	(27)
Leasehold and property acquisitions	(6)	(3)
Contributions to Altus equity method interests	(27)	(286)
Proceeds from sale of oil and gas properties	239	132
Other, net	44	(17)
NET CASH USED IN INVESTING ACTIVITIES	(425)	(1,276)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	290	87
Proceeds from Altus credit facility, net	33	184
Proceeds from note payable to APA Corporation, net	139	0
Fixed-rate debt borrowings	0	1,238
Payments on fixed-rate debt	(1,795)	(980)
Distributions to noncontrolling interest - Egypt	(203)	(61)
Distributions to Altus Preferred Unit limited partners	(34)	(11)
Distributions to APA Corporation	(311)	0
Dividends paid	(9)	(113)
Other, net	(17)	(43)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(1,907)	301
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	86	(85)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262	247
CASH AND CASH EQUIVALENTS AT END OF PERIOD	348	162
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	365	341
Income taxes paid, net of refunds	$ 415	$ 153

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CONSOLIDATED BALANCE SHEET (Unaudited) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
CURRENT ASSETS:
Cash and cash equivalents ($109 and $24 related to Altus VIE)	$ 348	$ 262
Receivables, net of allowance of $99 and $95	1,167	908
Other current assets (Note 6) ($9 and $5 related to Altus VIE)	599	676
Accounts receivable from APA Corporation	55	0
Total current assets	2,169	1,846
PROPERTY AND EQUIPMENT:
Oil and gas properties	40,205	41,819
Gathering, processing, and transmission facilities ($207 and $206 related to Altus VIE)	673	670
Other ($4 and $3 related to Altus VIE)	1,124	1,140
Less: Accumulated depreciation, depletion, and amortization ($22 and $13 related to Altus VIE)	(33,889)	(34,810)
Property and equipment, net	8,113	8,819
OTHER ASSETS:
Equity method interests (Note 7) ($1,538 and $1,555 related to Altus VIE)	1,538	1,555
Decommissioning security for sold Gulf of Mexico properties (Note 12)	740	0
Deferred charges and other ($8 and $5 related to Altus VIE)	514	526
Note receivable from APA Corporation (Note 2)	1,352	0
Total assets	14,426	12,746
CURRENT LIABILITIES:
Accounts payable ($9 and $6 related to Altus VIE)	643	444
Note payable to APA Corporation	243	0
Current debt	215	2
Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)	937	862
Total current liabilities	2,038	1,308
LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)	7,193	8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	169	215
Asset retirement obligation, long-term	1,912	1,888
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	1,186	0
Other ($126 and $144 related to Altus VIE)	527	602
Total deferred credits and other noncurrent liabilities	3,794	2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)	635	608
EQUITY (DEFICIT):
Common stock, $0.625 par, 1,000 and 860,000,000 shares authorized, respectively, 1,000 and 418,429,375 shares issued, respectively	0	262
Paid-in capital	9,532	11,735
Accumulated deficit	(9,726)	(10,461)
Treasury stock, at cost, 0 and 40,946,745 shares, respectively	0	(3,189)
Accumulated other comprehensive income	15	14
DEFICIT ATTRIBUTABLE TO APA CORPORATION	(179)	(1,639)
TOTAL EQUITY (DEFICIT)	766	(645)
TOTAL LIABILITIES AND EQUITY	14,426	12,746
Noncontrolling interests, Egypt
EQUITY (DEFICIT):
Noncontrolling interest	854	925
Noncontrolling Interest, Altus
EQUITY (DEFICIT):
Noncontrolling interest	$ 91	$ 69

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CONSOLIDATED BALANCE SHEET (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Cash and cash equivalents	$ 348	$ 262
Receivables, net of allowance	1,167	908
Other current assets	599	676
Gathering, processing and transmission facilities	673	670
Other property and equipment	1,124	1,140
Accumulated depreciation	33,889	34,810
Equity method interests	1,538	1,555
Accounts payable	643	444
Deferred charges and other	514	526
Other current liabilities	937	862
Long-term debt	7,193	8,770
Asset retirement obligation	1,912	1,888
Other current liabilities	$ 527	$ 602
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	1,000	860,000,000
Common stock, shares issued (in shares)	1,000	418,429,375
Treasury stock, shares (in shares)	0	40,946,745
Altus VIE
Cash and cash equivalents	$ 109	$ 24
Receivables, net of allowance	99	95
Other current assets	9	5
Gathering, processing and transmission facilities	207	206
Other property and equipment	4	3
Accumulated depreciation	22	13
Equity method interests	1,538	1,555
Accounts payable	9	6
Deferred charges and other	8	5
Other current liabilities	15	4
Long-term debt	657	624
Asset retirement obligation	67	64
Other current liabilities	$ 126	$ 144

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Unaudited) - USD ($) $ in Millions	Total	Noncontrolling interests, Egypt	Noncontrolling interests, Altus	PARENT COMPANY DEFICIT	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	Noncontrolling Interests	Noncontrolling Interests Noncontrolling interests, Egypt	Noncontrolling Interests Noncontrolling interests, Altus
Beginning balance at Dec. 31, 2019	$ 555
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	56
Distributions to noncontrolling interest	(11)	$ (61)									$ (61)
Ending balance at Sep. 30, 2020	600
Beginning balance at Dec. 31, 2019	4,465			$ 3,255	$ 261	$ 11,769	$ (5,601)	$ (3,190)	$ 16	$ 1,210
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to APA Corporation	(4,870)			(4,870)			(4,870)
Net income attributable to nonredeemable noncontrolling interest		(138)	$ (7)								(138)	$ (7)
Distributions to noncontrolling interest	(11)	(61)									(61)
Common dividends	(29)			(29)		(29)
Other	3			3	1	1		1
Ending balance at Sep. 30, 2020	(637)			(1,641)	262	11,741	(10,471)	(3,189)	16	1,004
Beginning balance at Jun. 30, 2020	592
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	19
Distributions payable to Altus Preferred Unit limited partners	(11)
Distributions to noncontrolling interest		(21)									(21)
Ending balance at Sep. 30, 2020	600
Beginning balance at Jun. 30, 2020	(636)			(1,635)	262	11,744	(10,467)	(3,189)	15	999
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to APA Corporation	(4)			(4)			(4)
Net income attributable to nonredeemable noncontrolling interest		24	2								24	2
Distributions to noncontrolling interest		(21)									(21)
Common dividends	(10)			(10)		(10)
Other	8			8		7			1
Ending balance at Sep. 30, 2020	(637)			(1,641)	262	11,741	(10,471)	(3,189)	16	1,004
Beginning balance at Dec. 31, 2020	608
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	73
Distributions payable to Altus Preferred Unit limited partners	(12)
Distributions to noncontrolling interest	(34)	(203)									(203)
Ending balance at Sep. 30, 2021	635
Beginning balance at Dec. 31, 2020	(645)			(1,639)	262	11,735	(10,461)	(3,189)	14	994
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to APA Corporation	653			653			653
Net income attributable to nonredeemable noncontrolling interest		132	32								132	32
Distributions to noncontrolling interest	(34)	(203)									(203)
Common dividends	(9)			(9)		(9)
APA Corporation share exchange	0				(262)	(2,927)		3,189
Distributions to APA Corporation	(19)			(19)		(19)
Holding Company Reorganization	839			839		757	82
Other	(14)			(4)		(5)			1	(10)
Ending balance at Sep. 30, 2021	766			(179)	0	9,532	(9,726)	0	15	945
Beginning balance at Jun. 30, 2021	617
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	30
Distributions payable to Altus Preferred Unit limited partners	(12)
Distributions to noncontrolling interest		(143)									(143)
Ending balance at Sep. 30, 2021	635
Beginning balance at Jun. 30, 2021	948			(92)	0	9,535	(9,642)	0	15	1,040
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to APA Corporation	(83)			(83)			(83)
Net income attributable to nonredeemable noncontrolling interest		49	$ 4								49	$ 4
Distributions to noncontrolling interest		$ (143)									$ (143)
Distributions to APA Corporation	(9)			(9)		(9)
Other	0			5		6	(1)			(5)
Ending balance at Sep. 30, 2021	$ 766			$ (179)	$ 0	$ 9,532	$ (9,726)	$ 0	$ 15	$ 945

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Unaudited) (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.025	$ 0.025	$ 0.1125	$ 0.075	$ 0.25

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Nature of Operations

9 Months Ended

Sep. 30, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

These consolidated financial statements have been prepared by Apache Corporation (Apache 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 recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, which contains a summary of the Company’s significant accounting policies and other disclosures.

On January 4, 2021, Apache announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache became a direct, wholly-owned subsidiary of APA Corporation (APA), and all of Apache’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 pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache 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 making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2021, the Company's significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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 Apache 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 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, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualifies as a variable interest entity under GAAP, for which Apache consolidates because a wholly-owned subsidiary of Apache has a controlling financial interest and was determined to be the primary beneficiary.

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 the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 7—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 management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of 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 3—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 9—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 12—Commitments and Contingencies), the estimate of income taxes (refer to Note 11—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 fair value measurements. 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 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, and Note 13—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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Oil and gas proved property	$	—	$	—	$	—	$	4,319
Gathering, processing, and transmission facilities	—		—		—		68
Goodwill	—		—		—		87
Inventory and other	18		—		18		18
Total Impairments	$	18	$	—	$	18	$	4,492

During the third quarter and first nine months of 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

During the first nine months of 2020, the Company recognized total asset impairments of $4.5 billion in connection 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 its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment. The Company recognized proved property impairments of $3.9 billion, $374 million, and $7 million in the U.S., Egypt, and North Sea, respectively, to reduce the carrying value of its oil and gas properties to the estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million 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, the Company separately recognized impairments of $13 million for the early termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.

The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting segment. Reductions in the estimated net present value of expected future cash flows from oil and gas properties resulted in fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.

Accounts Receivable from / Accounts Payable to APA

Accounts receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Generally, cash in this amount will be transferred to Apache or paid to APA in subsequent periods, after current period transactions are processed and net results of operations are determined. However, from time to time, Apache may estimate and transfer the cash settlement amount in the month the transactions are processed in order to minimize affiliate working capital balances. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Proved Properties:
U.S.	$	—	$	—	$	—	$	3,938
Egypt	—		—		—		374
North Sea	—		—		—		7
Total proved properties	$	—	$	—	$	—	$	4,319
Unproved Properties:
U.S.	$	2	$	34	$	19	$	80
Egypt	2		2		6		6
North Sea	1		—		1		—
Total unproved properties	$	5	$	36	$	26	$	86

Proved properties impaired during the first nine months of 2020 had an aggregate fair value of $1.9 billion.

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 3—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission Facilities

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

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

The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2021 and 2020.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, were $1.1 billion and $670 million as of September 30, 2021 and December 31, 2020, respectively. Refer to Note 15—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.

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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Production revenues from customers	$	1,562	$	1,002	$	4,294	$	2,905
Production revenues from non-customers	123		44		336		74
Total production revenues	$	1,685	$	1,046	$	4,630	$	2,979

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 and $8 million of reorganization costs were incurred in the third quarter and first nine months of 2021, respectively, primarily related to ongoing consulting and separation activities in the Company’s international operations.

The Company recorded $7 million and $44 million of TRS costs during the third quarter and first nine months of 2020, respectively. TRS costs incurred in the first nine months of 2020 relate to $41 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs.

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TRANSACTIONS WITH PARENT AFFILIATE

9 Months Ended

Sep. 30, 2021

Related Party Transactions [Abstract]

TRANSACTIONS WITH PARENT AFFILIATE

TRANSACTIONS WITH PARENT AFFILIATE

The Company completed the Holding Company Reorganization on March 1, 2021 and sold to APA all of the equity in the three Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The reorganization gave rise to a note payable by APA to Apache. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the three subsidiaries sold by Apache to APA.

The Company recognized interest income of approximately $15 million and $35 million on this note during the third quarter and first nine months of 2021, respectively, which is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2021 to PIK pursuant to the note.

The Company accounted for the divestiture of its subsidiaries as a transfer to an affiliate entity under common control and no longer consolidates the subsidiaries for periods subsequent to the Holding Company Reorganization. The carrying value of the net assets transferred was $483 million, which included approximately $292 million of Cash and cash equivalents, $163 million of Oil and gas properties, and working capital items. The Company continues to hold its existing assets in the U.S., Egypt, and U.K., and its current economic interests in ALTM and its subsidiary, Altus Midstream LP.

The Company continues to provide administrative and support operations to APA related to activities performed for the Suriname and Dominican Republic subsidiaries. The Company is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company in connection with its role as service provider. All reimbursements are based on actual costs incurred and no market premium is applied by the Company to APA. The Company incurred $5 million and $12 million in reimbursable corporate overhead charges for the third quarter and first nine months of 2021, respectively.

In August 2021, Apache entered into an promissory note with APA under which Apache may borrow up to $250 million from APA at APA’s discretion. The note has a term of one year, maturing on August 4, 2022, and bears interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of September 30, 2021, there was $243 million outstanding under this note, which is reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet.

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ACQUISITIONS AND DIVESTITURES

9 Months Ended

Sep. 30, 2021

Business Combination and Asset Acquisition [Abstract]

ACQUISITIONS AND DIVESTITURES

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 $174 million and the assumption of asset retirement obligations of $44 million. The Company has recognized a gain of approximately $63 million in connection with the sale. The transaction is subject to normal post-closing adjustments.

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

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

On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline.

As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews. Upon closing of the transaction, management will reevaluate whether Apache has a controlling financial interest and is the primary beneficiary of ALTM such that consolidation would continue to be required under the VIE model.

2020 Activity

During the first nine months of 2020, the Company completed non-core asset and leasehold sales, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $53 million. The Company recognized a gain of approximately $5 million upon closing of these transactions.

The Company also completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $3 million.

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CAPITALIZED EXPLORATORY WELL COSTS

9 Months Ended

Sep. 30, 2021

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $54 million and $197 million as of September 30, 2021 and December 31, 2020, respectively. The decrease is primarily attributable to the completion of the Holding Company Reorganization in which the Company sold its interests in Suriname, including approximately $135 million of exploratory well costs as of December 31, 2020, to APA. Refer to Note 2—Transactions with Parent Affiliate for more detail. The remaining exploratory well costs relate to North Sea offshore wells and Egypt onshore wells where additional drilling activity was offset by dry hole write-offs during the period.

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

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. The Company manages variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production by utilizing various types of financial instruments. The Company has elected not to designate any of its derivative contracts as cash flow hedges.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2021, the Company had derivative positions with 11 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.

Derivative Instruments

Commodity Derivative Instruments

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

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls	Weighted Average Fixed Price
October—December 2021	NYMEX WTI	1,012	$58.59
October—December 2021	Dated Brent	828	$61.44

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

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

As of September 30, 2021, the Company had the following open natural gas financial basis swap contracts:

		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2021	NYMEX Henry Hub/IF Waha	11,050	$(0.42)	—	—
October—December 2021	NYMEX Henry Hub/IF HSC	—	—	11,050	$(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

Embedded Derivatives

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP, a subsidiary of ALTM, issued and sold Series A Cumulative Redeemable Preferred Units (Preferred Units). Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, refer to “Fair Value Measurements” below and Note 13—Redeemable Noncontrolling Interest - Altus.

Pipeline Capacity Embedded Derivatives

During the fourth quarter of 2019 and first quarter of 2020, the Company entered into an agreement to assign a portion of its contracted capacity under an existing transportation agreement to a third party. Embedded in this agreement is an arrangement under which the Company has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. This feature requires bifurcation and measurement of the change in market value for each period. Unrealized gains or losses in the fair value of this feature are recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received are deferred and reflected in income over the original tenure of the host contract.

Fair Value Measurements

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
September 30, 2021
Liabilities:
Commodity derivative instruments	—		32		—		32		—		32
Pipeline capacity embedded derivatives	—		47		—		47		—		47
Preferred Units embedded derivative	—		—		120		120		—		120
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivative	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

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 the income approach, a Level 3 fair value measurement, and 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 feature, and anticipated dividend yields of the Preferred Units. As of the September 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 September 30, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	120	Option Model	Altus’ Imputed Interest Rate	5.53-11.54%
				Interest Rate Volatility	38.03%

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of September 30, 2021, while a one percent decrease would lead to a similar decrease in value as of September 30, 2021. The assumed expected timing until exercise of the exchange option as of September 30, 2021 was 4.70 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:

	September 30, 2021		December 31, 2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	31	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	168		192
Total derivative liabilities	$	199	$	192

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Realized:
Commodity derivative instruments	$	(37)	$	(83)	$	63	$	(119)
Foreign currency derivative instruments	—		—		—		(1)
Realized gain (loss), net	(37)		(83)		63		(120)
Unrealized:
Commodity derivative instruments	29		91		(43)		(3)
Pipeline capacity embedded derivatives	3		8		6		(62)
Foreign currency derivative instruments	—		3		—		(1)
Preferred units embedded derivative	5		(3)		19		(76)
Unrealized loss, net	37		99		(18)		(142)
Derivative instrument gains (losses), net	$	—	$	16	$	45	$	(262)

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

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

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OTHER CURRENT ASSETS

9 Months Ended

Sep. 30, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

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

	September 30, 2021		December 31, 2020
	(In millions)
Inventories	$	441	$	492
Drilling advances	102		113
Prepaid assets and other	56		71
Total Other current assets	$	599	$	676

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EQUITY METHOD INTERESTS

9 Months Ended

Sep. 30, 2021

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS

As of September 30, 2021 and December 31, 2020, the Company, through its ownership of Altus, had the following equity method interests in four Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests. The table below presents the ownership percentages held by the Company and associated carrying values for each entity:

	Interest	September 30, 2021		December 31, 2020
		(In millions)
Gulf Coast Express Pipeline, LLC	16.0%	$	277	$	284
EPIC Crude Holdings, LP	15.0%	165		176
Permian Highway Pipeline, LLC	26.7%	632		615
Shin Oak Pipeline (Breviloba, LLC)	33.0%	464		480
Total Altus equity method interests		$	1,538	$	1,555

As of September 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.

The following table presents the activity in Altus’ equity method interests for the nine months ended September 30, 2021:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2020	$	284	$	176	$	615	$	480	$	1,555
Capital contributions	—		2		25		—		27
Distributions	(37)		—		(52)		(39)		(128)
Equity income (loss), net	30		(14)		44		23		83
Accumulated other comprehensive income	—		1		—		—		1
Balance at September 30, 2021	$	277	$	165	$	632	$	464	$	1,538

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 Nine Months Ended September 30,
	2021		2020
	(In millions)
Operating revenues	$	812	$	531
Operating income	401		267
Net income	340		217
Other comprehensive income (loss)	4		(1)

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OTHER CURRENT LIABILITIES

9 Months Ended

Sep. 30, 2021

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES

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

	September 30, 2021		December 31, 2020
	(In millions)
Accrued operating expenses	$	135	$	91
Accrued exploration and development	167		167
Accrued compensation and benefits	180		170
Accrued interest	92		140
Accrued income taxes	54		25
Current asset retirement obligation	56		56
Current operating lease liability	87		116
Current portion of derivatives at fair value	31		—
Other	135		97
Total Other current liabilities	$	937	$	862

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ASSET RETIREMENT OBLIGATION

9 Months Ended

Sep. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

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

	September 30, 2021
	(In millions)
Asset retirement obligation, December 31, 2020	$	1,944
Liabilities incurred	3
Liabilities settled	(20)
Liabilities divested	(44)
Accretion expense	85
Asset retirement obligation, September 30, 2021	1,968
Less current portion	(56)
Asset retirement obligation, long-term	$	1,912

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DEBT AND FINANCING COSTS

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS

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

	September 30, 2021		December 31, 2020
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	6,344	$	8,052
Altus credit facility(2)	657		624
Apache credit facility(2)	440		150
Finance lease obligations	36		38
Unamortized discount	(29)		(35)
Debt issuance costs	(40)		(57)
Total debt	7,408		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,193	$	8,770

(1)    The fair values of the Company’s notes and debentures were $7.0 billion and $8.5 billion as of September 30, 2021 and December 31, 2020, respectively.

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

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

As of September 30, 2021, current debt included $213 million, net of discount, 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 quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes and accepted for purchase $1.7 billion aggregate principal amount of certain notes. Apache paid holders an aggregate $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $98 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During the nine months ended September 30, 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

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

In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2021. The facility is for general corporate purposes. As of September 30, 2021, there were $440 million of borrowings and an aggregate £478 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 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 the Company’s credit rating from BBB to BB+ on March 26, 2020.

There were no borrowings outstanding under the Company’s commercial paper program as of September 30, 2021 and December 31, 2020. The Company did not use its commercial paper program during the first six months of 2021 and terminated the program during the third quarter of 2021.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2021, there were no borrowings and £118 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2020, there were no borrowings and £34 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 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 September 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 Apache, APA Corporation, or any of its subsidiaries.

Financing Costs, Net

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	102	$	113	$	324	$	327
Amortization of debt issuance costs	1		2		6		6
Capitalized interest	—		(3)		—		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Interest income from APA Corporation, net	(15)		—		(35)		—
Financing costs, net	$	192	$	99	$	393	$	168

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INCOME TAXES

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

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

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

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.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2021

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2021, the Company has an accrued liability of approximately $68 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

For additional information on Legal Matters described below, refer to Note 11—Commitments and Contingencies to the consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Argentine Environmental Claims and Argentina Tariff

No material change in the status of the YPF Sociedad Anónima and Pioneer Natural Resources Company indemnities matter has occurred since the filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

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

Apollo Exploration Lawsuit

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

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested 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, four ex-employees of Apache Canada 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 three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases have been sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state 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.

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

Castex Lawsuit

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

Oklahoma Class Actions

The Company is a party to two purported class actions 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 of approximately $200 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. The amount 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.

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.

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. The defendants believe the plaintiff’s claims lack merit and intend to vigorously defend this lawsuit.

Environmental Matters

As of September 30, 2021, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

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

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

The Company is not aware of any environmental claims existing as of September 30, 2021 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 Obligation to Decommission Sold Properties

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

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

In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund its decommissioning obligations on certain of the Legacy GOM Assets that GOM Shelf is currently required to perform. 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 Properties 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.

As and when Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache, Apache will 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, Apache may be forced to effectively use its available cash to fund the deficit.

As of September 30, 2021, Apache estimates that its potential liability to fund decommissioning of GOM Legacy 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, in the third quarter of 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning contingency for sold Gulf of Mexico properties” in the Company’s consolidated balance sheet. The Company also recorded a $740 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 GOM Legacy Assets under the caption “Decommissioning security for sold Gulf of Mexico properties”. A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. 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.

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REDEMABLE NONCONTROLLING INTEREST - ALTUS

9 Months Ended

Sep. 30, 2021

Equity [Abstract]

REDEMABLE NONCONTROLLING INTEREST - ALTUS

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 carrying amount of the Preferred Units are recorded as “Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

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

Activity related to the Preferred Units is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions to Altus Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream LP net income	N/A	76
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(34)
Dividends payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	60
Accreted value adjustment	N/A	13
Redeemable noncontrolling interest — Preferred Unit at: September 30, 2021	660,694	635
Preferred Units embedded derivative(2)		120
		$	755

(1)    The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of September 30, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of September 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 $730 million.

(2)    Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 5—Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.

N/A - not applicable.

CAPITAL STOCK AND EQUITY

Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization, Apache recorded various intercompany activities during the first quarter ended March 31, 2021, as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail.

Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache.

Net Income (Loss) per Common Share

Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly-owned subsidiary of APA.

Common Stock Dividends

During the third quarter and the first nine months ended September 30, 2020, the Company paid $9 million and $113 million, respectively, in dividends on its common stock. During the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.

During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the nine months ended September 30, 2021, the Company paid $19 million in capital distributions to its parent, APA, which is reflected as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

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CAPITAL STOCK AND EQUITY

9 Months Ended

Sep. 30, 2021

Equity [Abstract]

CAPITAL STOCK AND EQUITY

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 carrying amount of the Preferred Units are recorded as “Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners” classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

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

Activity related to the Preferred Units is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions to Altus Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream LP net income	N/A	76
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(34)
Dividends payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	60
Accreted value adjustment	N/A	13
Redeemable noncontrolling interest — Preferred Unit at: September 30, 2021	660,694	635
Preferred Units embedded derivative(2)		120
		$	755

(1)    The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of September 30, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of September 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 $730 million.

(2)    Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 5—Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.

N/A - not applicable.

CAPITAL STOCK AND EQUITY

Upon consummation of the Holding Company Reorganization, each outstanding share of Apache common stock automatically converted into a share of APA common stock on a one-for-one basis. As a result, each stockholder of Apache now owns the same number of shares of APA common stock that such stockholder owned of Apache common stock immediately prior to the Holding Company Reorganization. As a result of the Holding Company Reorganization, Apache recorded various intercompany activities during the first quarter ended March 31, 2021, as capital transactions, which are reflected in Apache’s Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest. Refer to Note 2—Transactions with Parent Affiliate for more detail.

Additionally, in connection with the Holding Company Reorganization, Apache transferred to APA, and APA assumed, sponsorship of all of Apache’s stock plans along with all of Apache’s rights and obligations under each plan. Subsequent to the Holding Company Reorganization, stock-based compensation associated with APA equity awards granted and outstanding to Apache employees are reflected as capital contributions from APA to Apache.

Net Income (Loss) per Common Share

Net income (loss) per share for Apache is no longer required, as its shares are not publicly traded, and Apache is now a direct, wholly-owned subsidiary of APA.

Common Stock Dividends

During the third quarter and the first nine months ended September 30, 2020, the Company paid $9 million and $113 million, respectively, in dividends on its common stock. During the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.

During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the nine months ended September 30, 2021, the Company paid $19 million in capital distributions to its parent, APA, which is reflected as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

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BUSINESS SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2021

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

As of September 30, 2021, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company’s Midstream business is operated by Altus Midstream Company, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Quarter Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	465	$	233	$	484	$	—	$	—	$	1,182
Natural gas revenues	63		42		188		—		—		293
Natural gas liquids revenues	2		6		202		—		—		210
Oil, natural gas, and natural gas liquids production revenues	530		281		874		—		—		1,685
Purchased oil and gas sales	—		—		374		—		—		374
Midstream service affiliate revenues	—		—		—		35		(35)		—
	530		281		1,248		35		(35)		2,059
Operating Expenses:
Lease operating expenses	117		101		98		—		—		316
Gathering, processing, and transmission	4		8		82		9		(35)		68
Purchased oil and gas costs	—		—		396		—		—		396
Taxes other than income	—		—		52		2		—		54
Exploration	14		4		3		—		—		21
Depreciation, depletion, and amortization	128		61		143		3		—		335
Asset retirement obligation accretion	—		20		8		1		—		29
Impairments	—		18		—		—		—		18
	263		212		782		15		(35)		1,237
Operating Income(1)	$	267	$	69	$	466	$	20	$	—	822
Other Income (Expense):
Loss on offshore decommissioning contingency											(446)
Loss on divestitures, net											(2)
Other, net											40
General and administrative											(64)
Transaction, reorganization, and separation											(4)
Financing costs, net											(192)
Income Before Income Taxes											$	154

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Nine Months Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	1,299	$	690	$	1,325	$	—	$	—	$	3,314
Natural gas revenues	198		100		533		—		—		831
Natural gas liquids revenues	6		16		463		—		—		485
Oil, natural gas, and natural gas liquids production revenues	1,503		806		2,321		—		—		4,630
Purchased oil and gas sales	—		—		1,050		6		—		1,056
Midstream service affiliate revenues	—		—		—		99		(99)		—
	1,503		806		3,371		105		(99)		5,686
Operating Expenses:
Lease operating expenses	335		274		283		—		(1)		891
Gathering, processing, and transmission	8		28		225		24		(98)		187
Purchased oil and gas costs	—		—		1,147		5		—		1,152
Taxes other than income	—		—		139		10		—		149
Exploration	36		27		21		—		2		86
Depreciation, depletion, and amortization	395		208		416		9		—		1,028
Asset retirement obligation accretion	—		59		23		3		—		85
Impairments	—		18		—		—		—		18
	774		614		2,254		51		(97)		3,596
Operating Income (Loss)(1)	$	729	$	192	$	1,117	$	54	$	(2)	2,090
Other Income (Expense):
Derivative instrument gains, net											45
Loss on offshore decommissioning contingency											(446)
Gain on divestitures, net											65
Other, net											175
General and administrative											(226)
Transaction, reorganization, and separation											(8)
Financing costs, net											(393)
Income Before Income Taxes											$	1,302
Total Assets(2)	$	2,887	$	2,080	$	7,606	$	1,853	$	—	$	14,426

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Quarter Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	303	$	179	$	303	$	—	$	—	$	785
Natural gas revenues	74		13		77		—		—		164
Natural gas liquids revenues	2		5		90		—		—		97
Oil, natural gas, and natural gas liquids production revenues	379		197		470		—		—		1,046
Purchased oil and gas sales	—		—		73		1		—		74
Midstream service affiliate revenues	—		—		—		39		(39)		—
	379		197		543		40		(39)		1,120
Operating Expenses:
Lease operating expenses	102		79		79		—		(1)		259
Gathering, processing, and transmission	8		10		74		9		(38)		63
Purchased oil and gas costs	—		—		74		1		—		75
Taxes other than income	—		—		30		4		—		34
Exploration	10		10		34		—		4		58
Depreciation, depletion, and amortization	144		90		161		3		—		398
Asset retirement obligation accretion	—		18		8		1		—		27
	264		207		460		18		(35)		914
Operating Income (Loss)(1)	$	115	$	(10)	$	83	$	22	$	(4)	206
Other Income (Expense):
Derivative instrument gains, net											16
Loss on divestitures, net											(1)
Other, net											9
General and administrative											(52)
Transaction, reorganization, and separation											(7)
Financing costs, net											(99)
Income Before Income Taxes											$	72

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Nine Months Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	823	$	578	$	929	$	—	$	—	$	2,330
Natural gas revenues	209		39		169		—		—		417
Natural gas liquids revenues	6		15		211		—		—		232
Oil, natural gas, and natural gas liquids production revenues	1,038		632		1,309		—		—		2,979
Purchased oil and gas sales	—		—		235		2		—		237
Midstream service affiliate revenues	—		—		—		111		(111)		—
	1,038		632		1,544		113		(111)		3,216
Operating Expenses:
Lease operating expenses	312		234		313		—		(1)		858
Gathering, processing, and transmission	31		37		219		29		(110)		206
Purchased oil and gas costs	—		—		205		2		—		207
Taxes other than income	—		—		79		11		—		90
Exploration	51		26		100		—		10		187
Depreciation, depletion, and amortization	463		278		632		9		—		1,382
Asset retirement obligation accretion	—		54		24		3		—		81
Impairments	529		7		3,956		—		—		4,492
	1,386		636		5,528		54		(101)		7,503
Operating Income (Loss)(1)	$	(348)	$	(4)	$	(3,984)	$	59	$	(10)	(4,287)
Other Income (Expense):
Derivative instrument losses, net											(262)
Gain on divestitures											24
Other, net											41
General and administrative											(214)
Transaction, reorganization, and separation											(44)
Financing costs, net											(168)
Loss Before Income Taxes											$	(4,910)
Total Assets(2)	$	3,052	$	2,238	$	5,708	$	1,741	$	136	$	12,875

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

Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $19 million, $6 million, and $19 million, respectively, for the first nine months of 2021.

Operating loss of U.S. and Egypt includes leasehold and other asset impairments of $34 million and $2 million, respectively, for the third quarter of 2020.

Operating loss of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $4.0 billion, $535 million, and $7 million, respectively, for the first nine months of 2020.

(2)    Intercompany balances are excluded from total assets.

(3)    Includes noncontrolling interests in Egypt and Altus.

(4)    On March 1, 2021, the Company sold its Suriname and Dominican Republic operations to APA. Refer to Note 2—Transactions with Parent Affiliate for more details on the transaction.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. Apache’s consolidated financial statements reflect the impacts of the Holding Company Reorganization on a prospective basis, and results prior to completion of the Holding Company Reorganization have not been restated. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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 Apache 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 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, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualifies as a variable interest entity under GAAP, for which Apache consolidates because a wholly-owned subsidiary of Apache has a controlling financial interest and was determined to be the primary beneficiary.

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 the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations.

Use of Estimates

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities require management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of 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 3—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 9—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 12—Commitments and Contingencies), the estimate of income taxes (refer to Note 11—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

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 fair value measurements. 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 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, and Note 13—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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Oil and gas proved property	$	—	$	—	$	—	$	4,319
Gathering, processing, and transmission facilities	—		—		—		68
Goodwill	—		—		—		87
Inventory and other	18		—		18		18
Total Impairments	$	18	$	—	$	18	$	4,492

During the third quarter and first nine months of 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

During the first nine months of 2020, the Company recognized total asset impairments of $4.5 billion in connection 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 its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment. The Company recognized proved property impairments of $3.9 billion, $374 million, and $7 million in the U.S., Egypt, and North Sea, respectively, to reduce the carrying value of its oil and gas properties to the estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million 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, the Company separately recognized impairments of $13 million for the early termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.

The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting segment. Reductions in the estimated net present value of expected future cash flows from oil and gas properties resulted in fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million.

Accounts Receivable from and Accounts Payable to APA

Accounts Receivable from / Accounts Payable to APAAccounts receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Generally, cash in this amount will be transferred to Apache or paid to APA in subsequent periods, after current period transactions are processed and net results of operations are determined. However, from time to time, Apache may estimate and transfer the cash settlement amount in the month the transactions are processed in order to minimize affiliate working capital balances.

Property and Equipment

Property and Equipment The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

Oil and Gas Property

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

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

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

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

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

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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Proved Properties:
U.S.	$	—	$	—	$	—	$	3,938
Egypt	—		—		—		374
North Sea	—		—		—		7
Total proved properties	$	—	$	—	$	—	$	4,319
Unproved Properties:
U.S.	$	2	$	34	$	19	$	80
Egypt	2		2		6		6
North Sea	1		—		1		—
Total unproved properties	$	5	$	36	$	26	$	86

Proved properties impaired during the first nine months of 2020 had an aggregate fair value of $1.9 billion.

Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.

Gathering, Processing, and Transmission Facilities

Gathering, Processing, and Transmission Facilities

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

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

The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Revenue Recognition

Revenue Recognition

There have been no significant changes to the Company’s contracts with customers during the nine months ended September 30, 2021 and 2020.

Payments under all contracts with customers are typically due and received within a short-term period of one year or less after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, were $1.1 billion and $670 million as of September 30, 2021 and December 31, 2020, respectively. Refer to Note 15—Business Segment Information for a disaggregation of oil, gas, and natural gas production revenue by product and reporting segment.

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 September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Production revenues from customers	$	1,562	$	1,002	$	4,294	$	2,905
Production revenues from non-customers	123		44		336		74
Total production revenues	$	1,685	$	1,046	$	4,630	$	2,979

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2021

Accounting Policies [Abstract]

Schedule of Asset Impairments

Asset impairments recorded in connection with fair value assessments were as follows:

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

Schedule of Non-cash Impairments of Proved and Unproved Property and Equipment

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Proved Properties:
U.S.	$	—	$	—	$	—	$	3,938
Egypt	—		—		—		374
North Sea	—		—		—		7
Total proved properties	$	—	$	—	$	—	$	4,319
Unproved Properties:
U.S.	$	2	$	34	$	19	$	80
Egypt	2		2		6		6
North Sea	1		—		1		—
Total unproved properties	$	5	$	36	$	26	$	86

Schedule of Revenues from Contracts with Customers and Non-customers

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Production revenues from customers	$	1,562	$	1,002	$	4,294	$	2,905
Production revenues from non-customers	123		44		336		74
Total production revenues	$	1,685	$	1,046	$	4,630	$	2,979

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Positions

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

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls	Weighted Average Fixed Price
October—December 2021	NYMEX WTI	1,012	$58.59
October—December 2021	Dated Brent	828	$61.44

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

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

As of September 30, 2021, the Company had the following open natural gas financial basis swap contracts:

		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
October—December 2021	NYMEX Henry Hub/IF Waha	11,050	$(0.42)	—	—
October—December 2021	NYMEX Henry Hub/IF HSC	—	—	11,050	$(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

Schedule of Derivative Assets Measured at Fair Value

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
September 30, 2021
Liabilities:
Commodity derivative instruments	—		32		—		32		—		32
Pipeline capacity embedded derivatives	—		47		—		47		—		47
Preferred Units embedded derivative	—		—		120		120		—		120
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivative	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

Schedule of Derivative Liabilities Measured at Fair Value

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
September 30, 2021
Liabilities:
Commodity derivative instruments	—		32		—		32		—		32
Pipeline capacity embedded derivatives	—		47		—		47		—		47
Preferred Units embedded derivative	—		—		120		120		—		120
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivative	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

(1)    The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

Schedule of Fair Value Measurement Inputs

As of the September 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 September 30, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	120	Option Model	Altus’ Imputed Interest Rate	5.53-11.54%
				Interest Rate Volatility	38.03%

Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations

The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:

	September 30, 2021		December 31, 2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	31	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	168		192
Total derivative liabilities	$	199	$	192

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Realized:
Commodity derivative instruments	$	(37)	$	(83)	$	63	$	(119)
Foreign currency derivative instruments	—		—		—		(1)
Realized gain (loss), net	(37)		(83)		63		(120)
Unrealized:
Commodity derivative instruments	29		91		(43)		(3)
Pipeline capacity embedded derivatives	3		8		6		(62)
Foreign currency derivative instruments	—		3		—		(1)
Preferred units embedded derivative	5		(3)		19		(76)
Unrealized loss, net	37		99		(18)		(142)
Derivative instrument gains (losses), net	$	—	$	16	$	45	$	(262)

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OTHER CURRENT ASSETS (Tables)

9 Months Ended

Sep. 30, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Current Assets

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

	September 30, 2021		December 31, 2020
	(In millions)
Inventories	$	441	$	492
Drilling advances	102		113
Prepaid assets and other	56		71
Total Other current assets	$	599	$	676

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EQUITY METHOD INTERESTS (Tables)

9 Months Ended

Sep. 30, 2021

Equity Method Investments and Joint Ventures [Abstract]

Summary of Equity Method Investment Information

The table below presents the ownership percentages held by the Company and associated carrying values for each entity:

	Interest	September 30, 2021		December 31, 2020
		(In millions)
Gulf Coast Express Pipeline, LLC	16.0%	$	277	$	284
EPIC Crude Holdings, LP	15.0%	165		176
Permian Highway Pipeline, LLC	26.7%	632		615
Shin Oak Pipeline (Breviloba, LLC)	33.0%	464		480
Total Altus equity method interests		$	1,538	$	1,555

The following table presents the activity in Altus’ equity method interests for the nine months ended September 30, 2021:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2020	$	284	$	176	$	615	$	480	$	1,555
Capital contributions	—		2		25		—		27
Distributions	(37)		—		(52)		(39)		(128)
Equity income (loss), net	30		(14)		44		23		83
Accumulated other comprehensive income	—		1		—		—		1
Balance at September 30, 2021	$	277	$	165	$	632	$	464	$	1,538

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

	For the Nine Months Ended September 30,
	2021		2020
	(In millions)
Operating revenues	$	812	$	531
Operating income	401		267
Net income	340		217
Other comprehensive income (loss)	4		(1)

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OTHER CURRENT LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2021

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

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

	September 30, 2021		December 31, 2020
	(In millions)
Accrued operating expenses	$	135	$	91
Accrued exploration and development	167		167
Accrued compensation and benefits	180		170
Accrued interest	92		140
Accrued income taxes	54		25
Current asset retirement obligation	56		56
Current operating lease liability	87		116
Current portion of derivatives at fair value	31		—
Other	135		97
Total Other current liabilities	$	937	$	862

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ASSET RETIREMENT OBLIGATION (Tables)

9 Months Ended

Sep. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligation

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

	September 30, 2021
	(In millions)
Asset retirement obligation, December 31, 2020	$	1,944
Liabilities incurred	3
Liabilities settled	(20)
Liabilities divested	(44)
Accretion expense	85
Asset retirement obligation, September 30, 2021	1,968
Less current portion	(56)
Asset retirement obligation, long-term	$	1,912

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DEBT AND FINANCING COSTS (Tables)

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Schedule of Debt

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

	September 30, 2021		December 31, 2020
	(In millions)
Notes and debentures before unamortized discount and debt issuance costs(1)	$	6,344	$	8,052
Altus credit facility(2)	657		624
Apache credit facility(2)	440		150
Finance lease obligations	36		38
Unamortized discount	(29)		(35)
Debt issuance costs	(40)		(57)
Total debt	7,408		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,193	$	8,770

(1)    The fair values of the Company’s notes and debentures were $7.0 billion and $8.5 billion as of September 30, 2021 and December 31, 2020, respectively.

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

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

Schedule of Financing Costs, Net

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

	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	102	$	113	$	324	$	327
Amortization of debt issuance costs	1		2		6		6
Capitalized interest	—		(3)		—		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Interest income from APA Corporation, net	(15)		—		(35)		—
Financing costs, net	$	192	$	99	$	393	$	168

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REDEMABLE NONCONTROLLING INTEREST - ALTUS (Tables)

9 Months Ended

Sep. 30, 2021

Equity [Abstract]

Schedule of Preferred Units

Activity related to the Preferred Units is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions to Altus Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream LP net income	N/A	76
Redeemable noncontrolling interest — Preferred Unit at: December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(34)
Dividends payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	60
Accreted value adjustment	N/A	13
Redeemable noncontrolling interest — Preferred Unit at: September 30, 2021	660,694	635
Preferred Units embedded derivative(2)		120
		$	755

(1)    The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of September 30, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of September 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 $730 million.

(2)    Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 5—Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.

N/A - not applicable.

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BUSINESS SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2021

Segment Reporting [Abstract]

Schedule of Financial Segment Information

Financial information for each segment is presented below:

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Quarter Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	465	$	233	$	484	$	—	$	—	$	1,182
Natural gas revenues	63		42		188		—		—		293
Natural gas liquids revenues	2		6		202		—		—		210
Oil, natural gas, and natural gas liquids production revenues	530		281		874		—		—		1,685
Purchased oil and gas sales	—		—		374		—		—		374
Midstream service affiliate revenues	—		—		—		35		(35)		—
	530		281		1,248		35		(35)		2,059
Operating Expenses:
Lease operating expenses	117		101		98		—		—		316
Gathering, processing, and transmission	4		8		82		9		(35)		68
Purchased oil and gas costs	—		—		396		—		—		396
Taxes other than income	—		—		52		2		—		54
Exploration	14		4		3		—		—		21
Depreciation, depletion, and amortization	128		61		143		3		—		335
Asset retirement obligation accretion	—		20		8		1		—		29
Impairments	—		18		—		—		—		18
	263		212		782		15		(35)		1,237
Operating Income(1)	$	267	$	69	$	466	$	20	$	—	822
Other Income (Expense):
Loss on offshore decommissioning contingency											(446)
Loss on divestitures, net											(2)
Other, net											40
General and administrative											(64)
Transaction, reorganization, and separation											(4)
Financing costs, net											(192)
Income Before Income Taxes											$	154

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other(4)		Total(3)
	Upstream
For the Nine Months Ended September 30, 2021	(In millions)
Revenues:
Oil revenues	$	1,299	$	690	$	1,325	$	—	$	—	$	3,314
Natural gas revenues	198		100		533		—		—		831
Natural gas liquids revenues	6		16		463		—		—		485
Oil, natural gas, and natural gas liquids production revenues	1,503		806		2,321		—		—		4,630
Purchased oil and gas sales	—		—		1,050		6		—		1,056
Midstream service affiliate revenues	—		—		—		99		(99)		—
	1,503		806		3,371		105		(99)		5,686
Operating Expenses:
Lease operating expenses	335		274		283		—		(1)		891
Gathering, processing, and transmission	8		28		225		24		(98)		187
Purchased oil and gas costs	—		—		1,147		5		—		1,152
Taxes other than income	—		—		139		10		—		149
Exploration	36		27		21		—		2		86
Depreciation, depletion, and amortization	395		208		416		9		—		1,028
Asset retirement obligation accretion	—		59		23		3		—		85
Impairments	—		18		—		—		—		18
	774		614		2,254		51		(97)		3,596
Operating Income (Loss)(1)	$	729	$	192	$	1,117	$	54	$	(2)	2,090
Other Income (Expense):
Derivative instrument gains, net											45
Loss on offshore decommissioning contingency											(446)
Gain on divestitures, net											65
Other, net											175
General and administrative											(226)
Transaction, reorganization, and separation											(8)
Financing costs, net											(393)
Income Before Income Taxes											$	1,302
Total Assets(2)	$	2,887	$	2,080	$	7,606	$	1,853	$	—	$	14,426

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Quarter Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	303	$	179	$	303	$	—	$	—	$	785
Natural gas revenues	74		13		77		—		—		164
Natural gas liquids revenues	2		5		90		—		—		97
Oil, natural gas, and natural gas liquids production revenues	379		197		470		—		—		1,046
Purchased oil and gas sales	—		—		73		1		—		74
Midstream service affiliate revenues	—		—		—		39		(39)		—
	379		197		543		40		(39)		1,120
Operating Expenses:
Lease operating expenses	102		79		79		—		(1)		259
Gathering, processing, and transmission	8		10		74		9		(38)		63
Purchased oil and gas costs	—		—		74		1		—		75
Taxes other than income	—		—		30		4		—		34
Exploration	10		10		34		—		4		58
Depreciation, depletion, and amortization	144		90		161		3		—		398
Asset retirement obligation accretion	—		18		8		1		—		27
	264		207		460		18		(35)		914
Operating Income (Loss)(1)	$	115	$	(10)	$	83	$	22	$	(4)	206
Other Income (Expense):
Derivative instrument gains, net											16
Loss on divestitures, net											(1)
Other, net											9
General and administrative											(52)
Transaction, reorganization, and separation											(7)
Financing costs, net											(99)
Income Before Income Taxes											$	72

	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(3)
	Upstream
For the Nine Months Ended September 30, 2020	(In millions)
Revenues:
Oil revenues	$	823	$	578	$	929	$	—	$	—	$	2,330
Natural gas revenues	209		39		169		—		—		417
Natural gas liquids revenues	6		15		211		—		—		232
Oil, natural gas, and natural gas liquids production revenues	1,038		632		1,309		—		—		2,979
Purchased oil and gas sales	—		—		235		2		—		237
Midstream service affiliate revenues	—		—		—		111		(111)		—
	1,038		632		1,544		113		(111)		3,216
Operating Expenses:
Lease operating expenses	312		234		313		—		(1)		858
Gathering, processing, and transmission	31		37		219		29		(110)		206
Purchased oil and gas costs	—		—		205		2		—		207
Taxes other than income	—		—		79		11		—		90
Exploration	51		26		100		—		10		187
Depreciation, depletion, and amortization	463		278		632		9		—		1,382
Asset retirement obligation accretion	—		54		24		3		—		81
Impairments	529		7		3,956		—		—		4,492
	1,386		636		5,528		54		(101)		7,503
Operating Income (Loss)(1)	$	(348)	$	(4)	$	(3,984)	$	59	$	(10)	(4,287)
Other Income (Expense):
Derivative instrument losses, net											(262)
Gain on divestitures											24
Other, net											41
General and administrative											(214)
Transaction, reorganization, and separation											(44)
Financing costs, net											(168)
Loss Before Income Taxes											$	(4,910)
Total Assets(2)	$	3,052	$	2,238	$	5,708	$	1,741	$	136	$	12,875

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

Operating income of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $19 million, $6 million, and $19 million, respectively, for the first nine months of 2021.

Operating loss of U.S. and Egypt includes leasehold and other asset impairments of $34 million and $2 million, respectively, for the third quarter of 2020.

Operating loss of U.S., Egypt, and North Sea includes leasehold and other asset impairments of $4.0 billion, $535 million, and $7 million, respectively, for the first nine months of 2020.

(2)    Intercompany balances are excluded from total assets.

(3)    Includes noncontrolling interests in Egypt and Altus.

(4)    On March 1, 2021, the Company sold its Suriname and Dominican Republic operations to APA. Refer to Note 2—Transactions with Parent Affiliate for more details on the transaction.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)	Jun. 30, 2020
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 18	$ 0		$ 18	$ 4,492
Impairment for early termination of drilling rig leases			$ 13
Inventory write-down			$ 5
Goodwill	0	0		0	87
Gathering, processing and transmission facilities	673			673		$ 670
Accumulated depreciation	33,889			33,889		34,810
Receivables from contracts with customer, net	1,100			1,100		670
Restructuring cumulative cost incurred to date						$ 79
Transaction, reorganization, and separation	4	7		8	44
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Goodwill				87
Separation costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation					41
Consulting fees
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation					2
Office closure
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation					1
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges	0	0		0	4,319
Impairments of oil and gas properties	0	0		0	4,319
Oil and gas properties impaired, fair value		$ 1,900			$ 1,900
Oil and gas proved property | Discount Rate | Significant Unobservable Inputs (Level 3)
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas properties, measurement inputs		0.10	0.10		0.10		0.10
Oil and gas proved property | U.S.
Schedule Of Significant Accounting Policies [Line Items]
Impairments of oil and gas properties	0	$ 0	$ 3,900	0	$ 3,938
Oil and gas proved property | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments of oil and gas properties	0	0		0	374
Oil and gas proved property | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments of oil and gas properties	0	0	7	0	7
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges	$ 0	$ 0		$ 0	$ 68
Oil and gas properties impaired, fair value			46
Gathering, processing, and transmission facilities | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments			$ 68
Third-Party Investors | Altus Midstream Company
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	21.00%			21.00%
Sinopec | Apache Egypt
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners	33.33%			33.33%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Impairments Recorded in Connection with Fair Value Assessments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Schedule Of Significant Accounting Policies [Line Items]
Goodwill	$ 0	$ 0	$ 0	$ 87
Inventory and other	18	0	18	18
Total Impairments	18	0	18	4,492
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges	0	0	0	4,319
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges	$ 0	$ 0	$ 0	$ 68

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 0	$ 0		$ 0	$ 4,319
Oil and gas proved property | U.S.
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	0	$ 3,900	0	3,938
Oil and gas proved property | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	0		0	374
Oil and gas proved property | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	0	$ 7	0	7
Oil and gas unproved properties
Schedule Of Significant Accounting Policies [Line Items]
Impairments	5	36		26	86
Oil and gas unproved properties | U.S.
Schedule Of Significant Accounting Policies [Line Items]
Impairments	2	34		19	80
Oil and gas unproved properties | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments	2	2		6	6
Oil and gas unproved properties | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 1	$ 0		$ 1	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Revenues from Contracts with Customers and Non-customers (Details) - Oil and gas, excluding purchased - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Schedule Of Significant Accounting Policies [Line Items]
Production revenues from customers	$ 1,562	$ 1,002	$ 4,294	$ 2,905
Production revenues from non-customers	123	44	336	74
Total production revenues	$ 1,685	$ 1,046	$ 4,630	$ 2,979

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TRANSACTIONS WITH PARENT AFFILIATE (Details) $ in Millions			3 Months Ended		9 Months Ended
	Aug. 04, 2021 USD ($)	Mar. 01, 2021 USD ($) subsidiary	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)
Related Party Transaction [Line Items]
Interest income from APA Corporation, net			$ 15	$ 0	$ 35	$ 0
Reimbursable costs charged to Parent			5		12
Affiliated Entity | Promissory Note
Related Party Transaction [Line Items]
Debt face amount	$ 250
Debt term	1 year
Short-term debt			$ 243		$ 243
Affiliated Entity | Holding Company Reorganization
Related Party Transaction [Line Items]
Number of subsidiaries | subsidiary		3
Note receivable, term		7 years
Note receivable, interest rate		4.50%
Note receivable, accrued interest converted to principal, term		5 years 6 months
Affiliated Entity | Holding Company Reorganization | Disposed of by Sale | Three Apache Subsidiaries
Related Party Transaction [Line Items]
Net assets transferred		$ 483
Cash and cash equivalents transferred		292
Oil and gas properties, and working capital items transferred		$ 163

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ACQUISITIONS AND DIVESTITURES (Details) - USD ($) shares in Millions, $ in Millions		3 Months Ended	9 Months Ended
	Oct. 21, 2021	Jun. 30, 2021	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Business Acquisition [Line Items]
Property and equipment, net			$ 8,113		$ 8,819
Proceeds from sale of oil and gas properties			239	$ 132
Leasehold and property acquisitions			6	3
Common Class C | BCP | ALTM | Subsequent Event
Business Acquisition [Line Items]
Business acquisition, equity interest issued or issuable, number of shares	50
Permian Highway Pipeline, LLC | BCP | Subsequent Event
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by parent	26.70%
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions			6	3
Permian Region | Disposed of by Sale
Business Acquisition [Line Items]
Property and equipment, net		$ 157
Proceeds from sale of oil and gas properties		174		53
Asset retirement obligation assumed		44
Gain (loss) on sale of non-core assets		$ 63		$ 5
Permian Region | Disposed of by Sale | Other Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties			65
Gain (loss) on sale of non-core assets			$ 2

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CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Capitalized exploratory well costs	$ 54	$ 197
Capitalized exploratory well costs that have been capitalized for period greater than one year		$ 135

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Details) bbl in Thousands, MMBTU in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) $ / MMBTU $ / bbl MMBTU Counterparty bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty	11
Fixed Price Swaps | October—December 2021 | Crude Oil | NYMEX WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in Mbbls) | bbl	1,012
Derivative weighted average fixed price (USD per bbl) | $ / bbl	58.59
Fixed Price Swaps | October—December 2021 | Crude Oil | Dated Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in Mbbls) | bbl	828
Derivative weighted average fixed price (USD per bbl) | $ / bbl	61.44
Basis Swap | October—December 2021 | Crude Oil | Midland-WTI/Cushing-WTI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in Mbbls) | bbl	1,012
Weighted average price differential | $ / bbl	0.70
Basis Swap Purchased | October—December 2021 | Natural Gas | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	11,050
Weighted average price differential | $ / MMBTU	(0.42)
Basis Swap Purchased | January—December 2022 | Natural Gas | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.45)
Basis Swap Purchased | January—December 2023 | Natural Gas | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	29,200
Weighted average price differential | $ / MMBTU	(0.40)
Basis Swap Sold | October—December 2021 | Natural Gas | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	11,050
Weighted average price differential | $ / MMBTU	(0.07)
Basis Swap Sold | January—December 2022 | Natural Gas | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.08)
Basis Swap Sold | January—December 2023 | Natural Gas | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	29,200
Weighted average price differential | $ / MMBTU	0.02
Financial Contracts, Gas Daily Pricing
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized gain in connection with contracts | $	$ 147

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Assets:
Derivative asset	$ 0	$ 11
Liabilities:
Derivative liability	199	192
Commodity derivative instruments
Assets:
Derivative asset, fair value		11
Derivative asset, netting		0
Derivative asset		11
Liabilities:
Derivative liability, fair value	32
Derivative liability, netting	0
Derivative liability	32
Commodity derivative instruments | Quoted Price in Active Markets (Level 1)
Assets:
Derivative asset, fair value		0
Liabilities:
Derivative liability, fair value	0
Commodity derivative instruments | Significant Other Inputs (Level 2)
Assets:
Derivative asset, fair value		11
Liabilities:
Derivative liability, fair value	32
Commodity derivative instruments | Significant Unobservable Inputs (Level 3)
Assets:
Derivative asset, fair value		0
Liabilities:
Derivative liability, fair value	0
Pipeline capacity embedded derivatives
Liabilities:
Derivative liability, fair value	47	53
Derivative liability, netting	0	0
Derivative liability	47	53
Pipeline capacity embedded derivatives | Quoted Price in Active Markets (Level 1)
Liabilities:
Derivative liability, fair value	0	0
Pipeline capacity embedded derivatives | Significant Other Inputs (Level 2)
Liabilities:
Derivative liability, fair value	47	53
Pipeline capacity embedded derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative liability, fair value	0	0
Preferred Units embedded derivative
Liabilities:
Derivative liability, fair value	120	139
Derivative liability, netting	0	0
Derivative liability	120	139
Preferred Units embedded derivative | Quoted Price in Active Markets (Level 1)
Liabilities:
Derivative liability, fair value	0	0
Preferred Units embedded derivative | Significant Other Inputs (Level 2)
Liabilities:
Derivative liability, fair value	0	0
Preferred Units embedded derivative | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative liability, fair value	$ 120	$ 139

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value Measurement Inputs (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Expected timing until exercise of exchange option	4 years 8 months 12 days
Recurring
Derivative [Line Items]
Derivative liability	$ 199	$ 192
Preferred Units embedded derivative | Recurring
Derivative [Line Items]
Derivative liability	$ 120	$ 139
Significant Unobservable Inputs (Level 3) | Measurement Input, Risk Free Interest Rate | Minimum
Derivative [Line Items]
Embedded derivative liability, measurement input	0.0553
Significant Unobservable Inputs (Level 3) | Measurement Input, Risk Free Interest Rate | Maximum
Derivative [Line Items]
Embedded derivative liability, measurement input	0.1154
Significant Unobservable Inputs (Level 3) | Measurement Input, Interest Rate Volatility
Derivative [Line Items]
Embedded derivative liability, measurement input	0.3803

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0	$ 11
Derivative liability	199	192
Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	0	6
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	0	5
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	31	0
Deferred Credits and Other Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	$ 168	$ 192

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized loss, net			$ (18)	$ (142)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	$ (37)	$ (83)	63	(120)
Unrealized loss, net	37	99	(18)	(142)
Derivative instrument gains (losses), net	0	16	45	(262)
Commodity derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	(37)	(83)	63	(119)
Unrealized loss, net	29	91	(43)	(3)
Pipeline capacity embedded derivatives | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized loss, net	3	8	6	(62)
Foreign currency derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	0	0	0	(1)
Unrealized loss, net	0	3	0	(1)
Preferred units embedded derivative | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized loss, net	$ 5	$ (3)	$ 19	$ (76)

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OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 441	$ 492
Drilling advances	102	113
Prepaid assets and other	56	71
Total Other current assets	$ 599	$ 676

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EQUITY METHOD INTERESTS - Additional Information (Details) $ in Millions	Sep. 30, 2021 USD ($) pipeline_entity	Dec. 31, 2020 USD ($) pipeline_entity
Equity Method Investments and Joint Ventures [Abstract]
Number of long-haul pipeline entities | pipeline_entity	4	4
Difference between carrying amount and underlying equity amount | $	$ 37	$ 38

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EQUITY METHOD INTERESTS - Summary of Investments (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 1,538	$ 1,555
Gulf Coast Express Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Interest percentage	16.00%
Equity method interests	$ 277	284
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Interest percentage	15.00%
Equity method interests	$ 165	176
Permian Highway Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Interest percentage	26.70%
Equity method interests	$ 632	615
Shin Oak Pipeline (Breviloba, LLC)
Schedule of Equity Method Investments [Line Items]
Interest percentage	33.00%
Equity method interests	$ 464	$ 480

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EQUITY METHOD INTERESTS - Rollforward Activity (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	$ 1,555
Capital contributions	27	$ 286
Distributions	(128)
Equity income (loss), net	83
Accumulated other comprehensive income	1
Equity method interest, ending balance	1,538
Gulf Coast Express Pipeline, LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	284
Capital contributions	0
Distributions	(37)
Equity income (loss), net	30
Accumulated other comprehensive income	0
Equity method interest, ending balance	277
EPIC Crude Holdings, LP
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	176
Capital contributions	2
Distributions	0
Equity income (loss), net	(14)
Accumulated other comprehensive income	1
Equity method interest, ending balance	165
Permian Highway Pipeline, LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	615
Capital contributions	25
Distributions	(52)
Equity income (loss), net	44
Accumulated other comprehensive income	0
Equity method interest, ending balance	632
Shin Oak Pipeline (Breviloba, LLC)
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance	480
Capital contributions	0
Distributions	(39)
Equity income (loss), net	23
Accumulated other comprehensive income	0
Equity method interest, ending balance	$ 464

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EQUITY METHOD INTERESTS - Summary of Combined Statement of Operations Equity Method Interests (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Schedule of Equity Method Investments [Line Items]
Operating income	$ 822	$ 206	$ 2,090	$ (4,287)
Net income	$ 0	$ 41	890	(4,959)
Equity Method Investment, Nonconsolidated Investee or Group of Investees
Schedule of Equity Method Investments [Line Items]
Operating revenues			812	531
Operating income			401	267
Net income			340	217
Other comprehensive income (loss)			$ 4	$ (1)

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OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Accrued operating expenses	$ 135	$ 91
Accrued exploration and development	167	167
Accrued compensation and benefits	180	170
Accrued interest	92	140
Accrued income taxes	54	25
Current asset retirement obligation	56	56
Current operating lease liability	87	116
Current portion of derivatives at fair value	31	0
Other	135	97
Total Other current liabilities	$ 937	$ 862

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ASSET RETIREMENT OBLIGATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at the beginning of period			$ 1,944
Liabilities incurred			3
Liabilities settled			(20)
Liabilities divested			44
Accretion expense	$ 29	$ 27	85	$ 81
Asset retirement obligation at the end of period	1,968		1,968
Less current portion	(56)		(56)		$ (56)
Asset retirement obligation, long-term	$ 1,912		$ 1,912		$ 1,888

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Finance lease obligations	$ 36	$ 38
Unamortized discount	(29)	(35)
Debt issuance costs	(40)	(57)
Total debt	7,408	8,772
Current maturities	(215)	(2)
Long-term debt	7,193	8,770
Notes and debentures
Debt Instrument [Line Items]
Debt instrument, fair value	7,000	8,500
Notes and debentures | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross	6,344	8,052
Altus credit facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	657	624
Apache credit facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	$ 440	$ 150

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DEBT AND FINANCING COSTS - Additional Information (Details) £ in Millions	1 Months Ended		3 Months Ended		9 Months Ended
	Mar. 31, 2019 USD ($)	Nov. 30, 2018 USD ($) contract	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 GBP (£)	Dec. 31, 2020 USD ($)	Dec. 31, 2020 GBP (£)	Mar. 31, 2018 USD ($)
Debt Instrument [Line Items]
Finance lease obligations, current				$ 2,000,000		$ 2,000,000		$ 2,000,000
Gain (loss) on extinguishment of debt			$ (105,000,000)	$ 12,000,000	$ (104,000,000)	$ 152,000,000
Commercial paper outstanding			0		0			0
Apache credit facility
Debt Instrument [Line Items]
Letters of credit outstanding, amount			17,000,000		17,000,000		£ 118	17,000,000	£ 34
Line of credit outstanding			0		0			0
Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, committed amount										$ 4,000,000,000
Debt extension term	1 year
Senior Notes | Debt Repurchase, Cash Tender Offers
Debt Instrument [Line Items]
Debt repurchased principal amount			1,700,000,000		1,700,000,000
Debt instrument repurchase program			1,800,000,000		1,800,000,000
Gain (loss) on extinguishment of debt			(105,000,000)
Net of discount			98,000,000		98,000,000
Senior Notes | Open Market Repurchase
Debt Instrument [Line Items]
Debt repurchased principal amount			22,000,000		22,000,000
Debt instrument repurchase program			20,000,000		20,000,000
Gain (loss) on extinguishment of debt					1,000,000
Discount to par of debt repurchase					2,000,000
Senior Notes | Senior Notes Due April 15, 2022
Debt Instrument [Line Items]
Current debt outstanding amount			$ 213,000,000		$ 213,000,000
Debt instrument, stated interest rate			3.25%		3.25%		3.25%
Line of Credit | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Debt extension term		1 year
Credit facility maximum borrowing capacity		$ 800,000,000
Line of credit facility, number of extension options | contract		2
Line of credit facility, maximum borrowing capacity if adding new lenders		$ 1,500,000,000
Line of Credit | Letter of Credit | Altus Midstream LP
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		100,000,000
Line of Credit | Swingline Loan Subfacility | Altus Midstream LP
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		$ 100,000,000
Line of Credit | Apache credit facility
Debt Instrument [Line Items]
Borrowing amount			$ 440,000,000		$ 440,000,000			150,000,000
Line of Credit | Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 5,000,000,000
Line of Credit | Apache credit facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, committed amount			2,080,000,000.00		2,080,000,000.00
Credit facility maximum borrowing capacity			3,000,000,000		3,000,000,000
Letters of credit outstanding, amount			20,000,000		20,000,000		£ 478	40,000,000	£ 633
Line of Credit | Altus credit facility
Debt Instrument [Line Items]
Borrowing amount			657,000,000		657,000,000			624,000,000
Line of Credit | Altus credit facility | Altus Midstream LP
Debt Instrument [Line Items]
Letters of credit outstanding, amount			2,000,000		2,000,000			0
Line of Credit | Altus credit facility | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit outstanding			$ 657,000,000		$ 657,000,000			$ 624,000,000

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Debt Disclosure [Abstract]
Interest expense	$ 102	$ 113	$ 324	$ 327
Amortization of debt issuance costs	1	2	6	6
Capitalized interest	0	(3)	0	(9)
Loss (gain) on extinguishment of debt	105	(12)	104	(152)
Interest income	(1)	(1)	(6)	(4)
Interest income from APA Corporation, net	(15)	0	(35)	0
Financing costs, net	$ 192	$ 99	$ 393	$ 168

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COMMITMENTS AND CONTINGENCIES (Details) $ in Millions							3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 10, 2020 defendant	Sep. 11, 2019 USD ($) plaintiff	Dec. 20, 2017 Action	Jul. 17, 2017 Action defendant	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Sep. 30, 2021 USD ($) sidetrack bond subsidiary	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($) sidetrack Action subsidiary bond	Sep. 30, 2020 USD ($)	Dec. 31, 2013 USD ($) source	Mar. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Aug. 03, 2020 USD ($)	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies							$ 68,000,000		$ 68,000,000
Undiscounted reserve for environmental remediation							2,000,000		2,000,000
Standby loan agreed to provide related to ARO														$ 400,000,000
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)							1,186,000,000		1,186,000,000				$ 0
Decommissioning security for sold Gulf of Mexico properties (Note 12)							740,000,000		740,000,000				$ 0
Loss on offshore decommissioning contingency							$ 446,000,000	$ 0	$ 446,000,000	$ 0
Gulf Of Mexico Shelf Operations and Properties | Disposed of by Sale
Commitment And Contingencies [Line Items]
Proceeds from sale of operations and properties											$ 3,750,000,000
Trust account for disposal group, number of net profits interests | source											2
Number of debt instruments held | subsidiary							5		5
Number of bonds held | bond							2		2
Minimum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							$ 1,200,000,000		$ 1,200,000,000
Maximum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							1,400,000,000		1,400,000,000
3750000000
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages					$ 200,000,000
3750000000 | Minimum
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages						$ 1,100,000,000
Australian Operations Divestiture Dispute | Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount																$ 80
Loss contingency, estimated of possible loss amount															$ 200
Canadian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages		$ 60,000,000
Number of plaintiffs | plaintiff		4
California Litigation
Commitment And Contingencies [Line Items]
Number of actions filed | Action			2	3
Number of defendants | defendant				30
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants | defendant	25
Castex Lawsuit
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages									200,000,000
Loss contingency, estimated of possible loss amount							$ 13,500,000		$ 13,500,000			$ 60,000,000
Number of sidetracks | sidetrack							5		5
Oklahoma Class Actions
Commitment And Contingencies [Line Items]
Plaintiffs alleged damages									$ 200,000,000
Number of actions filed | Action									2

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REDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) - Altus Midstream LP - Altus Preferred Unit limited partners $ in Millions	Jun. 12, 2019 USD ($)
Class of Stock [Line Items]
Aggregate issue price of Preferred Units	$ 625
Proceeds from issuance or sale of equity	$ 611

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REDEMABLE NONCONTROLLING INTEREST - ALTUS - Activity Related to Preferred Units (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Dec. 31, 2020
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	$ 617	$ 592	$ 608	$ 555
Dividends payable to Altus Preferred Unit limited partners	(12)	(11)	(12)
Ending balance	635	$ 600	635	$ 608
Altus Midstream LP
Increase (Decrease) in Temporary Equity [Roll Forward]
Preferred Units embedded derivative	120		120
Redeemable noncontrolling interest, net of embedded derivative liability	$ 755		$ 755
Preferred units, redemption terms, internal rate of return	11.50%		11.50%
Preferred units, invested capital	$ 813		$ 813
Preferred units, redemption value	$ 730		$ 730
Altus Midstream LP | Altus Preferred Unit limited partners
Movement In Preferred Units [Roll Forward]
Preferred units: beginning of period (in shares)			660,694	638,163
Distribution of in-kind additional preferred units (in shares)				22,531
Preferred units: end of period (in shares)	660,694,000		660,694,000	660,694
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance			$ 608	$ 555
Distribution of in-kind additional Preferred Units				0
Cash distributions to Altus Preferred Unit limited partners				(23)
Dividends payable to Altus Preferred Unit limited partners			(12)
Allocation of Altus Midstream LP net income			60	76
Accreted value adjustment			13
Ending balance	$ 635		$ 635	$ 608
Preferred units, redemption terms, multiple of invested capital	1.3		1.3

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CAPITAL STOCK AND EQUITY (Details) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2020 USD ($) $ / shares	Mar. 31, 2020 $ / shares	Sep. 30, 2021 USD ($) $ / shares	Sep. 30, 2020 USD ($) $ / shares	Dec. 31, 2019 $ / shares	Mar. 01, 2021
Equity [Abstract]
Common stock, conversion ratio						1
Dividends, Common Stock, Cash	$ 10		$ 9	$ 29
Common stock, dividends, per share (in USD per share) | $ / shares	$ 0.025	$ 0.025	$ 0.1125	$ 0.075	$ 0.25
Payments of dividend on common stock	$ 9		$ 9	$ 113

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BUSINESS SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($) Segment	Sep. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)
Segment Reporting [Abstract]
Number of operating segments | Segment			3
Segment Reporting Information [Line Items]
Lease operating expenses	$ 316	$ 259	$ 891	$ 858
Taxes other than income	54	34	149	90
Exploration	21	58	86	187
Depreciation, depletion, and amortization	335	398	1,028	1,382
Asset retirement obligation accretion	29	27	85	81
Impairments	18	0	18	4,492
Total operating expenses	1,237	914	3,596	7,503
Operating income	822	206	2,090	(4,287)
Other Income (Expense):
Derivative instrument gains (losses), net	0	16	45	(262)
Loss on offshore decommissioning contingency	(446)		(446)
Loss on divestitures, net	(2)	(1)	65	24
Other, net	40	9	175	41
General and administrative	(64)	(52)	(226)	(214)
Transaction, reorganization, and separation	(4)	(7)	(8)	(44)
Financing costs, net	(192)	(99)	(393)	(168)
NET INCOME (LOSS) BEFORE INCOME TAXES	154	72	1,302	(4,910)
Total assets	14,426	12,875	14,426	12,875	$ 12,746
Operating Segments | Egypt
Segment Reporting Information [Line Items]
Lease operating expenses	117	102	335	312
Taxes other than income	0	0	0	0
Exploration	14	10	36	51
Depreciation, depletion, and amortization	128	144	395	463
Asset retirement obligation accretion	0	0	0	0
Impairments	0		0	529
Total operating expenses	263	264	774	1,386
Operating income	267	115	729	(348)
Other Income (Expense):
Total assets	2,887	3,052	2,887	3,052
Impairments of oil and gas properties	2	2	6	535
Operating Segments | North Sea
Segment Reporting Information [Line Items]
Lease operating expenses	101	79	274	234
Taxes other than income	0	0	0	0
Exploration	4	10	27	26
Depreciation, depletion, and amortization	61	90	208	278
Asset retirement obligation accretion	20	18	59	54
Impairments	18		18	7
Total operating expenses	212	207	614	636
Operating income	69	(10)	192	(4)
Other Income (Expense):
Total assets	2,080	2,238	2,080	2,238
Impairments of oil and gas properties	19		19	7
Operating Segments | U.S.
Segment Reporting Information [Line Items]
Lease operating expenses	98	79	283	313
Taxes other than income	52	30	139	79
Exploration	3	34	21	100
Depreciation, depletion, and amortization	143	161	416	632
Asset retirement obligation accretion	8	8	23	24
Impairments	0		0	3,956
Total operating expenses	782	460	2,254	5,528
Operating income	466	83	1,117	(3,984)
Other Income (Expense):
Total assets	7,606	5,708	7,606	5,708
Impairments of oil and gas properties	2	34	19	4,000
Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Production revenues from customers	35	39	99	111
Lease operating expenses	0	0	0	0
Taxes other than income	2	4	10	11
Exploration	0	0	0	0
Depreciation, depletion, and amortization	3	3	9	9
Asset retirement obligation accretion	1	1	3	3
Impairments	0		0	0
Total operating expenses	15	18	51	54
Operating income	20	22	54	59
Other Income (Expense):
Total assets	1,853	1,741	1,853	1,741
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Production revenues from customers	(35)	(39)	(99)	(111)
Lease operating expenses	0	(1)	(1)	(1)
Taxes other than income	0	0	0	0
Exploration	0	4	2	10
Depreciation, depletion, and amortization	0	0	0	0
Asset retirement obligation accretion	0	0	0	0
Impairments	0		0	0
Total operating expenses	(35)	(35)	(97)	(101)
Operating income	0	(4)	(2)	(10)
Other Income (Expense):
Total assets	0	136	0	136
Oil and gas
Segment Reporting Information [Line Items]
Total revenues	2,059	1,120	5,686	3,216
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues	530	379	1,503	1,038
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues	281	197	806	632
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues	1,248	543	3,371	1,544
Oil and gas | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues	35	40	105	113
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	(35)	(39)	(99)	(111)
Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	1,685	1,046	4,630	2,979
Production revenues from customers	1,562	1,002	4,294	2,905
Cost of goods and services sold	68	63	187	206
Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	530	379	1,503	1,038
Cost of goods and services sold	4	8	8	31
Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	281	197	806	632
Cost of goods and services sold	8	10	28	37
Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	874	470	2,321	1,309
Cost of goods and services sold	82	74	225	219
Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Cost of goods and services sold	9	9	24	29
Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Cost of goods and services sold	(35)	(38)	(98)	(110)
Oil and gas, purchased
Segment Reporting Information [Line Items]
Production revenues from customers	374	74	1,056	237
Cost of goods and services sold	396	75	1,152	207
Oil and gas, purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Production revenues from customers	0	0	0	0
Cost of goods and services sold	0	0	0	0
Oil and gas, purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Production revenues from customers	0	0	0	0
Cost of goods and services sold	0	0	0	0
Oil and gas, purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Production revenues from customers	374	73	1,050	235
Cost of goods and services sold	396	74	1,147	205
Oil and gas, purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Production revenues from customers	0	1	6	2
Cost of goods and services sold	0	1	5	2
Oil and gas, purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Production revenues from customers	0	0	0	0
Cost of goods and services sold	0	0	0	0
Oil | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	1,182	785	3,314	2,330
Oil | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	465	303	1,299	823
Oil | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	233	179	690	578
Oil | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	484	303	1,325	929
Oil | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Oil | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Natural Gas | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	293	164	831	417
Natural Gas | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	63	74	198	209
Natural Gas | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	42	13	100	39
Natural Gas | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	188	77	533	169
Natural Gas | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Natural Gas | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Natural Gas liquids | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	210	97	485	232
Natural Gas liquids | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	2	2	6	6
Natural Gas liquids | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	6	5	16	15
Natural Gas liquids | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	202	90	463	211
Natural Gas liquids | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	0	0	0	0
Natural Gas liquids | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues	$ 0	$ 0	$ 0	$ 0