Oil & Gas 360General form for quarterly reports under Section 13 or 15(d) - Form 10-Q

apa-20210930

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


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

For the transition period from _________ to _________

Commission File Number: 1-40144

APA CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.625 par value

APA

Nasdaq Global Select Market

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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


Number of shares of registrant’s common stock outstanding as of October 31, 2021			363,274,259

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 DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48
4.	CONTROLS AND PROCEDURES	49

	PART II - OTHER INFORMATION
1.	LEGAL PROCEEDINGS	50
1A.	RISK FACTORS	50
2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50
6.	EXHIBITS	51

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 Annual Report on Form 10-K of Apache Corporation, the Company’s predecessor registrant, 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 “APA,” the “Company,” “we,” “us,” and “our” refer to APA Corporation and its consolidated subsidiaries, including Apache Corporation, unless otherwise specifically stated. References to “Apache” refer to Apache Corporation, the Company’s wholly-owned subsidiary, and its consolidated subsidiaries, unless otherwise specifically stated.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions, except share data)
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	34		58		109		187
General and administrative	70		52		239		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	205		99		422		168
	1,529		1,072		4,288		7,929
NET INCOME (LOSS) BEFORE INCOME TAXES	122		72		1,237		(4,910)
Current income tax provision	183		58		463		120
Deferred income tax benefit	(31)		(27)		(54)		(71)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(30)		41		828		(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 COMMON STOCK	$	(113)	$	(4)	$	591	$	(4,870)

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.30)	$	(0.01)	$	1.56	$	(12.89)
Diluted	$	(0.30)	$	(0.02)	$	1.53	$	(12.89)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	379		378		378		378
Diluted	379		378		379		378

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	(30)	$	41	$	828	$	(4,959)
OTHER COMPREHENSIVE INCOME, NET OF TAX:
Share of equity method interests other comprehensive income	—		1		1		—
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(30)		42		829		(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 COMMON STOCK	$	(113)	$	(3)	$	592	$	(4,870)

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2021		2020
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$	828	$	(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	67		138
Depreciation, depletion, and amortization	1,028		1,382
Asset retirement obligation accretion	85		81
Impairments	18		4,492
Deferred income tax benefit	(54)		(71)
Loss (gain) on extinguishment of debt	104		(152)
Loss on previously sold Gulf of Mexico properties	446		—
Other, net	(6)		45
Changes in operating assets and liabilities:
Receivables	(265)		202
Inventories	(19)		16
Drilling advances and other current assets	32		(5)
Deferred charges and other long-term assets	(46)		(12)
Accounts payable	219		(211)
Accrued expenses	29		(211)
Deferred credits and noncurrent liabilities	(8)		37
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,411		890
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(790)		(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	(542)		(1,276)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	290		87
Proceeds from Altus credit facility, net	33		184

Fixed-rate debt borrowings	—		1,238
Payments on Apache fixed-rate debt	(1,795)		(980)
Distributions to noncontrolling interest - Egypt	(203)		(61)
Distributions to Altus Preferred Unit limited partners	(34)		(11)
Dividends paid to APA common stockholders	(28)		(113)
Other, net	(17)		(43)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(1,754)		301

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	115		(85)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262		247
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	377	$	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.

APA 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)	$	377	$	262
Receivables, net of allowance of $99 and $95	1,170		908
Other current assets (Note 5) ($9 and $5 related to Altus VIE)	634		676
	2,181		1,846
PROPERTY AND EQUIPMENT:
Oil and gas properties	40,428		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)
	8,336		8,819
OTHER ASSETS:
Equity method interests (Note 6) ($1,538 and $1,555 related to Altus VIE)	1,538		1,555
Decommissioning security for sold Gulf of Mexico properties (Note 11)	740		—
Deferred charges and other ($8 and $5 related to Altus VIE)	515		526
	$	13,310	$	12,746

LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable ($9 and $6 related to Altus VIE)	$	687	$	444
Current debt	215		2
Other current liabilities (Note 7) ($15 and $4 related to Altus VIE)	937		862
	1,839		1,308
LONG-TERM DEBT (Note 9) ($657 and $624 related to Altus VIE)	7,193		8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	166		215
Asset retirement obligation (Note 8) ($67 and $64 related to Altus VIE)	1,912		1,888
Decommissioning contingency for sold Gulf of Mexico properties (Note 11)	1,186		—
Other ($126 and $144 related to Altus VIE)	529		602
	3,793		2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	635		608
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 418,965,522 and 418,429,375 shares issued, respectively	262		262
Paid-in capital	11,686		11,735
Accumulated deficit	(9,870)		(10,461)
Treasury stock, at cost, 40,943,612 and 40,946,745 shares, respectively	(3,188)		(3,189)
Accumulated other comprehensive income	15		14
APA SHAREHOLDERS’ DEFICIT	(1,095)		(1,639)
Noncontrolling interest - Egypt	854		925
Noncontrolling interest - Altus	91		69
TOTAL EQUITY (DEFICIT)	(150)		(645)
	$	13,310	$	12,746

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

APA CORPORATION AND SUBSIDIARIES

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

(Unaudited)


	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income		APA SHAREHOLDERS’ DEFICIT		Noncontrolling Interests		TOTAL 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 common stock	—		—		—		(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	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76
Net loss attributable to common stock	—		—		—		(113)		—		—		(113)		—		(113)
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		49		49
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		4		4
Net income attributable to Altus Preferred Unit limited partners	30		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	—		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(143)		(143)
Common dividends declared ($0.0625 per share)	—		—		(24)		—		—		—		(24)		—		(24)
Other	—		—		6		—		—		—		6		(5)		1
Balance at September 30, 2021	$	635	$	262	$	11,686	$	(9,870)	$	(3,188)	$	15	$	(1,095)	$	945	$	(150)

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

APA CORPORATION AND SUBSIDIARIES

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

(Unaudited)


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

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

APA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

These consolidated financial statements have been prepared by APA Corporation (APA or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements, with the exception of 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 Annual Report on Form 10-K of Apache Corporation, the Company’s predecessor registrant, 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 Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly-owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s 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 APA consolidates because a wholly-owned subsidiary of APA 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 6—Equity Method Interests for further detail.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities require 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 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 8—Asset Retirement Obligation), the estimation of the contingent liability representing Apache’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 11—Commitments and Contingencies), the estimate of income taxes (refer to Note 10—Income Taxes), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. The Company determines fair value measurements in accordance with Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), which provides a hierarchy that prioritizes and defines the types of inputs used to base 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 4—Derivative Instruments and Hedging Activities, Note 9—Debt and Financing Costs, and Note 12—Redeemable Noncontrolling Interest - Altus for further detail regarding the Company’s fair value measurements recorded on a recurring basis.

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


	For the Quarter Ended 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.

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 2—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 APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

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

The Company assessed its long-lived infrastructure assets for impairment 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 14—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.

2. ACQUISITIONS AND DIVESTITURES

2021 Activity

During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $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.

Suriname Joint Venture Agreement

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

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

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

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $277 million and $197 million as of September 30, 2021 and December 31, 2020, respectively. The increase is primarily attributable to additional drilling activity in Suriname and Egypt, partially 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.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. 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 12—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.

5. OTHER CURRENT ASSETS

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


	September 30, 2021		December 31, 2020
	(In millions)
Inventories	$	476	$	492
Drilling advances	102		113

Prepaid assets and other	56		71
Total Other current assets	$	634	$	676

6. 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)

7. 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

8. 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

9. DEBT AND FINANCING COSTS

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


	September 30, 2021		December 31, 2020
	(In millions)
Apache 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
Apache 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 Apache notes and debentures were $7.0 billion and $8.5 billion as of September 30, 2021 and December 31, 2020, respectively.

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

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

As of September 30, 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.

In March 2018, Apache 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. Apache 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 Apache’s credit rating from BBB to BB+ on March 26, 2020.

There were no borrowings outstanding under Apache’s commercial paper program as of September 30, 2021 and December 31, 2020. Apache 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	(2)		(3)		(6)		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Financing costs, net	$	205	$	99	$	422	$	168

10. INCOME TAXES

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

During the third quarter of 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.

11. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of September 30, 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 Apache Corporation’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 Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Louisiana Restoration

As more fully described in Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, 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. 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.

12. REDEEMABLE NONCONTROLLING INTEREST - ALTUS

Preferred Units Issuance

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

Classification

The 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)
Distributions 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 4 —Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.

N/A - not applicable.

13. CAPITAL STOCK

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

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

Net Income (Loss) per Common Share

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


	For the Quarter Ended September 30,
	2021					2020
	Loss		Shares	Per Share		Loss		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	(113)	379	$	(0.30)	$	(4)	378	$	(0.01)
Effect of Dilutive Securities:

Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	—	—	$	—	$	(4)	—	$	(0.01)
Diluted:
Income (loss) attributable to common stock	$	(113)	379	$	(0.30)	$	(8)	378	$	(0.02)

	For the Nine Months Ended September 30,
	2021					2020
	Income		Shares	Per Share		Loss		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	591	378	$	1.56	$	(4,870)	378	$	(12.89)
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	—	$	—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	(10)		—	(0.03)		—		—	—
Diluted:
Income (loss) attributable to common stock	$	581	379	$	1.53	$	(4,870)	378	$	(12.89)

The Company uses the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream LP for shares of Altus Midstream Company’s common stock. The impact to net income and loss attributable to common stock on an assumed conversion of the Preferred Units was anti-dilutive for the quarter ended September 30, 2021 and for the nine months ended September 30, 2020. The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 3.2 million and 4.2 million during the third quarters of 2021 and 2020, respectively, and 3.4 million and 5.1 million during the first nine months of 2021 and 2020, respectively.

Stock Repurchase Program

During the fourth quarter of 2018, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. No shares were purchased under this authorization through September 30, 2021. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. In both cases, shares may be purchased either in the open market or through privately held negotiated transactions.

The Company repurchased 14.7 million shares at an average price of $26.50 per share in October 2021, and as of October 31, 2021, the Company had remaining authorization to repurchase up to 65.3 million shares. The Company is not obligated to acquire any additional shares.

Common Stock Dividends

During each of the quarters ended September 30, 2021 and 2020, the Company paid $9 million in dividends on its common stock. During the nine months ended September 30, 2021 and 2020, the Company paid $28 million and $113 million, respectively, in dividends on its common stock.

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

14. 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. The Company also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Financial information for each segment is presented below:


	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(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		—		13		34
Depreciation, depletion, and amortization	128		61		143		3		—		335
Asset retirement obligation accretion	—		20		8		1		—		29
Impairments	—		18		—		—		—		18
	263		212		782		15		(22)		1,250
Operating Income (Loss)(1)	$	267	$	69	$	466	$	20	$	(13)	809

Other Income (Expense):

Loss on offshore decommissioning contingency											(446)
Loss on divestitures, net											(2)
Other, net											40
General and administrative											(70)
Transaction, reorganization, and separation											(4)
Financing costs, net											(205)
Income Before Income Taxes											$	122


	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		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		—		25		109
Depreciation, depletion, and amortization	395		208		416		9		—		1,028
Asset retirement obligation accretion	—		59		23		3		—		85
Impairments	—		18		—		—		—		18
	774		614		2,254		51		(74)		3,619
Operating Income (Loss)(1)	$	729	$	192	$	1,117	$	54	$	(25)	2,067

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

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


	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.

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

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

Overview

APA is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The 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, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its 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 $113 million, or $0.30 per diluted common share, compared to a net loss of $4 million, or $0.01 per diluted common share, 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 11 —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 171 percent increase from the first nine months of 2020, driven by higher commodity prices and associated revenues. Since year-end 2020, the Company reduced its outstanding debt by $1.4 billion, and it had $377 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, as follows:

•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.

•The Company currently plans to return a minimum of 60 percent of its free cash flow to shareholders through dividends, share buybacks, or a combination thereof. In the third quarter of 2021, the Company announced a quarterly dividend increase from $0.025 per share to $0.0625 per share and, in the fourth quarter, announced a further increase to $0.125 per share. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. The Company repurchased 14.7 million shares in October 2021, and as of October 31, 2021, the Company had remaining authorization to repurchase up to 65.3 million shares under Company’s share repurchase programs. The optimal balance of cash return through dividends and share repurchases will be reviewed on a regular basis.

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, the Company 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.

•In late 2020, the Company commenced drilling a fourth exploration well at the Keskesi prospect in Block 58 offshore Suriname. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with ongoing exploration and appraisal activities continuing to progress. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding a 50 percent working interest.

•TotalEnergies is currently running two rigs. One is conducting a flow test at the Sapakara South appraisal well, and the other is drilling the Bonboni exploration well in the northern portion of Block 58.

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.

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.

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.

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.

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	34		58		109		187
General and administrative	70		52		239		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	205		99		422		168
Total Operating Expenses	$	1,529	$	1,072	$	4,288	$	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.

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	16		5		41		52
Geological and geophysical expense	4		7		14		14
Exploration overhead and other	9		10		28		35
Total Exploration	$	34	$	58	$	109	$	187

Exploration expenses decreased $24 million and $78 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 $18 million and $25 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’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.

Impairments

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	(2)		(3)		(6)		(9)
Loss (gain) on extinguishment of debt	105		(12)		104		(152)
Interest income	(1)		(1)		(6)		(4)
Total Financing costs, net	$	205	$	99	$	422	$	168

Net financing costs increased $106 million and $254 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.

Provision for Income Taxes

The Company recorded a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

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

The Company’s capital investment for the third quarter of 2021 was below its planned budget announced earlier in the year, but the Company remains on-track for its full-year guidance and estimated upstream capital program of $1.1 billion. The program consists of approximately $900 million for development activities across its portfolio and approximately $200 million for exploration activities, predominantly in Suriname.

The Company believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, and amounts that may ultimately be paid in connection with commitments and contingencies.

The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.

For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Sources and Uses of Cash

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


	For the Nine Months Ended September 30,
	2021		2020
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,411	$	890
Proceeds from Apache credit facility, net	290		87
Proceeds from Altus credit facility, net	33		184
Proceeds from asset divestitures	239		132
Fixed-rate debt borrowings	—		1,238
Other	27		—
Total Sources of Cash and Cash Equivalents	3,000		2,531
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property(1)	$	(790)	$	(1,075)
Additions to Altus gathering, processing, and transmission facilities(1)	(2)		(27)
Leasehold and property acquisitions	(6)		(3)
Contributions to Altus equity method interests	(27)		(286)


Payments on fixed-rate debt	(1,795)		(980)
Dividends paid to APA common stockholders	(28)		(113)
Distributions to noncontrolling interest - Egypt	(203)		(61)
Distributions to Altus Preferred Unit limited partners	(34)		(11)

Other	—		(60)
Total Uses of Cash and Cash Equivalents	(2,885)		(2,616)
Increase (decrease) in cash and cash equivalents	$	115	$	(85)

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

Sources of Cash and Cash Equivalents

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities increased $1.5 billion from the first nine months of 2020, primarily due to higher commodity prices.

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

Proceeds from Apache Credit Facility, Net During the first nine months of 2021 and 2020, Apache borrowed $290 million and $87 million, respectively, under its revolving credit facility.

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity method pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first nine months of 2021 and 2020, Altus Midstream LP borrowed $33 million and $184 million, respectively, under its revolving credit facility to meet this short fall. With the midstream infrastructure complete and all of the equity method interest pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program during 2021.

Proceeds from Asset Divestitures The Company received $239 million and $132 million of proceeds from the divestiture of certain non-core assets during the first nine months of 2021 and 2020, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $790 million and $1.1 billion during the first nine months of 2021 and 2020, respectively. The decrease in capital investment is reflective of the Company’s reduced capital program to align with anticipated operating cash flows following the collapse of commodity prices stemming from the COVID-19 pandemic. The Company operated an average of 14 drilling rigs during the third quarter of 2021, compared to an average of eight drilling rigs during the third quarter of 2020.

Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $2 million and $27 million during the first nine months of 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for the remainder of 2021 to be minimal.

Leasehold and Property Acquisitions The Company completed leasehold and property acquisitions for total cash consideration of $6 million and $3 million during the first nine months of 2021 and 2020.

Contributions to Altus Equity Method Interests Altus contributed $27 million and $286 million in cash during the first nine months of 2021 and 2020, respectively, for equity interests in the equity method interest pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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

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

On August 18, 2020, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.

During the quarter ended September 30, 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $89 million for an aggregate purchase price of $79 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $11 million. These repurchases resulted in a $10 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under the Company’s revolving credit facility.

During the quarter ended June 30, 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $410 million for an aggregate purchase price of $267 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $147 million. These repurchases resulted in a $140 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under the Company’s revolving credit facility.

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

Dividends The Company paid $28 million and $113 million during the first nine months of 2021 and 2020, respectively, for dividends on its common stock. In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $203 million and $61 million during the first nine months of 2021 and 2020, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $34 million and $11 million in cash distributions to its limited partners holding Preferred Units during the first nine months of 2021 and 2020, respectively. For more information regarding the Preferred Units, refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Liquidity

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


	September 30, 2021		December 31, 2020
	(In millions)
Cash and cash equivalents	$	377	$	262
Total debt - Apache	6,751		8,148
Total debt - Altus	657		624
Total deficit	(150)		(645)
Available committed borrowing capacity - Apache	2,896		2,944
Available committed borrowing capacity - Altus	141		176

Cash and Cash Equivalents As of September 30, 2021, the Company had $377 million in cash and cash equivalents, of which approximately $109 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of September 30, 2021, the Company had $7.4 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. As of September 30, 2021, current debt included $213 million, net of discount, of 3.625% senior notes due April 15, 2022 and $2 million of finance lease obligations.

Committed Credit Facilities In March 2018, Apache 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. Apache 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. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.

As of September 30, 2021, there were $440 million of borrowings and 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 Apache’s credit rating from BBB to BB+ on March 26, 2020.

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

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

Commercial Paper Program Apache did not use its commercial paper program during the first six months of 2021 and terminated the program during the third quarter of 2021. As of December 31, 2020, no commercial paper was outstanding.

Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations as described in “Contractual Obligations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

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

In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A 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.

If the combination of GOM Shelf’s net cash flows 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. 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.

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” above and in Note 11 —Commitments and Contingencie s 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

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. These factors have only been heightened as the result of continuing negative demand implications of the COVID-19 pandemic became more apparent. The Company continually monitors its market risk exposure, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets subsequent to the year ended December 31, 2019.

The Company’s average crude oil price realizations increased 75 percent from $40.88 per barrel to $71.72 per barrel during the third quarters of 2020 and 2021, respectively. The Company’s average natural gas price realizations increased 104 percent from $1.90 per Mcf to $3.87 per Mcf during the third quarters of 2020 and 2021, respectively. The Company’s average NGL price realizations increased 133 percent from $13.51 per barrel to $31.42 per barrel during the third quarters of 2020 and 2021, respectively. Based on average daily production for the third quarter of 2021, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $16 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $7 million.

The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of September 30, 2021, the Company had open natural gas derivatives, not designated as cash flow hedges, in a liability position with a fair value of approximately $2 million. A 10 percent increase in basis differential of the hedges would increase the liability by approximately $8 million, while a 10 percent decrease in basis differential of the hedges would move the derivatives to an asset position of approximately $6 million. As of September 30, 2021, the Company had open crude oil derivatives, not designated as cash flow hedges, in a liability position with a fair value of approximately $30 million. A 10 percent increase in oil prices would increase the liability by approximately $19 million, while a 10 percent decrease in oil prices would decrease the liability by approximately $19 million. These fair value changes assume volatility based on prevailing market parameters as of September 30, 2021. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

As of September 30, 2021, the Company had $6.3 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.07 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt. The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the indentures and credit facilities. As of September 30, 2021, the Company had approximately $377 million in cash and cash equivalents, approximately 55 percent of which was invested in money market funds and short-term investments with major financial institutions. As of September 30, 2021, there were $440 million and $657 million of borrowings outstanding under the Apache Corporation and Altus Midstream LP revolving credit facilities, respectively. A change in the interest rate applicable to short-term investments and credit facility borrowings would have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.

Foreign Currency Exchange Rate Risk

The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is primarily sold under U.S. dollar contracts and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $4 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of September 30, 2021.

The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. The Company had no outstanding foreign exchange derivative contracts as of September 30, 2021.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of 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.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Part I, Item 3—Legal Proceedings of Apache Corporation’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 Apache Corporation’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, Apache Corporation and Altus Midstream Company may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the applicable disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021, 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.

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

ITEM 6. EXHIBITS


2.1	–	Agreement and Plan of Merger, dated as of March 1, 2021, by and among Apache Corporation, Registrant, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-40144).
3.1	–	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-40144).
3.2	–	Amended and Restated Bylaws of Registrant, dated September 14, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 20, 2021, SEC File No. 001-40144).
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101	–	The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 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

SIGNATURES

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


		APA CORPORATION

Dated:	November 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)

Document

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:


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

Date: November 4, 2021


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

Document

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:


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

Date: November 4, 2021


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

Document

EXHIBIT 32.1

APA CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of APA Corporation for the quarterly period ending September 30, 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 APA 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 APA 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 APA Corporation.

Date: November 4, 2021


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

Legal Notice

General form for quarterly reports under Section 13 or 15(d) – Form 10-Q

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