SEC Filing | APA Corporation

View:

Download DOC

Download PDF

Download XLS

Download XBRL

apa-20210630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2021


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

For the transition period from _________ to _________

Commission File Number: 1-40144

APA CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices) (Zip Code)

(713) 296-6000

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, $0.625 par value

APA

Nasdaq Global Select Market

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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


Number of shares of registrant’s common stock outstanding as of July 31, 2021			378,021,539

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	30
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
4.	CONTROLS AND PROCEDURES	44

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



6.	EXHIBITS	46

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 variant) 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 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 second-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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	1,514	$	697	$	2,945	$	1,933
Purchased oil and gas sales	242		55		682		163
Total revenues	1,756		752		3,627		2,096
Derivative instrument gains (losses), net	(113)		(175)		45		(278)
Gain on divestitures, net	65		—		67		25
Other, net	74		19		135		32
	1,782		596		3,874		1,875
OPERATING EXPENSES:
Lease operating expenses	311		264		575		599
Gathering, processing, and transmission	61		72		119		143
Purchased oil and gas costs	262		46		756		132
Taxes other than income	51		23		95		56
Exploration	26		72		75		129
General and administrative	86		94		169		162
Transaction, reorganization, and separation	4		10		4		37
Depreciation, depletion, and amortization	351		418		693		984
Asset retirement obligation accretion	28		27		56		54
Impairments	—		20		—		4,492
Financing costs, net	107		(34)		217		69
	1,287		1,012		2,759		6,857
NET INCOME (LOSS) BEFORE INCOME TAXES	495		(416)		1,115		(4,982)
Current income tax provision (benefit)	131		(27)		280		62
Deferred income tax benefit	(44)		(11)		(23)		(44)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	408		(378)		858		(5,000)
Net income (loss) attributable to noncontrolling interest - Egypt	41		(11)		83		(162)
Net income (loss) attributable to noncontrolling interest - Altus	27		—		28		(9)
Net income attributable to Altus Preferred Unit limited partners	24		19		43		37
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	316	$	(386)	$	704	$	(4,866)

NET INCOME (LOSS) PER COMMON SHARE:


Basic	$	0.83	$	(1.02)	$	1.86	$	(12.88)



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

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

APA CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


	For the Six Months Ended June 30,
	2021		2020
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$	858	$	(5,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses, net	55		241
Gain on divestitures, net	(67)		(25)
Exploratory dry hole expense and unproved leasehold impairments	46		97
Depreciation, depletion, and amortization	693		984
Asset retirement obligation accretion	56		54
Impairments	—		4,492
Deferred income tax benefit	(23)		(44)
Gain on extinguishment of debt	(1)		(140)
Other, net	(14)		14
Changes in operating assets and liabilities:
Receivables	(165)		183
Inventories	20		25
Drilling advances and other current assets	43		(26)
Deferred charges and other long-term assets	(18)		(16)
Accounts payable	157		(147)
Accrued expenses	17		(148)
Deferred credits and noncurrent liabilities	(17)		42
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,640		586
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(558)		(838)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(1)		(25)
Leasehold and property acquisitions	(3)		(3)
Contributions to Altus equity method interests	(24)		(154)

Proceeds from sale of oil and gas properties	181		126
Other, net	12		(23)
NET CASH USED IN INVESTING ACTIVITIES	(393)		(917)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from (payments on) Apache credit facility, net	(150)		565
Proceeds from Altus credit facility, net	33		97

Payments on Apache fixed-rate debt	(20)		(264)
Distributions to noncontrolling interest - Egypt	(60)		(40)
Distributions to Altus Preferred Unit limited partners	(23)		—

Dividends paid to APA common stockholders	(19)		(104)
Other, net	(21)		(35)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(260)		219

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

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

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

APA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	June 30, 2021		December 31, 2020
	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($75 and $24 related to Altus VIE)	$	1,249	$	262
Receivables, net of allowance of $99 and $95	1,068		908
Other current assets (Note 5) ($9 and $5 related to Altus VIE)	628		676
	2,945		1,846
PROPERTY AND EQUIPMENT:
Oil and gas properties	40,437		41,819


Gathering, processing, and transmission facilities ($206 and $206 related to Altus VIE)	668		670
Other ($4 and $3 related to Altus VIE)	1,140		1,140
Less: Accumulated depreciation, depletion, and amortization ($19 and $13 related to Altus VIE)	(33,744)		(34,810)
	8,501		8,819
OTHER ASSETS:
Equity method interests (Note 6) ($1,554 and $1,555 related to Altus VIE)	1,554		1,555
Deferred charges and other ($9 and $5 related to Altus VIE)	512		526
	$	13,512	$	12,746

LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	603	$	444
Current debt	215		2
Other current liabilities (Note 7) ($11 and $4 related to Altus VIE)	955		862
	1,773		1,308
LONG-TERM DEBT (Note 9) ($657 and $624 related to Altus VIE)	8,420		8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	194		215
Asset retirement obligation (Note 8) ($66 and $64 related to Altus VIE)	1,893		1,888
Other ($131 and $144 related to Altus VIE)	539		602
	2,626		2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 12)	617		608
EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 418,960,548 and 418,429,375 shares issued, respectively	262		262
Paid-in capital	11,704		11,735
Accumulated deficit	(9,757)		(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	(964)		(1,639)
Noncontrolling interest - Egypt	948		925
Noncontrolling interest - Altus	92		69
TOTAL EQUITY (DEFICIT)	76		(645)
	$	13,512	$	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 (Loss)		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Quarter Ended June 30, 2020
Balance at March 31, 2020	$	573	$	262	$	11,747	$	(10,081)	$	(3,189)	$	15	$	(1,246)	$	1,018	$	(228)
Net loss attributable to common stock	—		—		—		(386)		—		—		(386)		—		(386)
Net loss attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(11)		(11)


Net income attributable to Altus Preferred Unit holders	19		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(8)		(8)
Common dividends declared ($0.025 per share)	—		—		(9)		—		—		—		(9)		—		(9)
Other	—		—		6		—		—		—		6		—		6
Balance at June 30, 2020	$	592	$	262	$	11,744	$	(10,467)	$	(3,189)	$	15	$	(1,635)	$	999	$	(636)

For the Quarter Ended June 30, 2021
Balance at March 31, 2021	$	605	$	262	$	11,727	$	(10,073)	$	(3,189)	$	15	$	(1,258)	$	997	$	(261)
Net income attributable to common stock	—		—		—		316		—		—		316		—		316
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		41		41
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		27		27
Net income attributable to Altus Preferred Unit limited partners	24		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—

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

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 (Loss)		APA SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)
For the Six Months Ended June 30, 2020
Balance at December 31, 2019	$	555	$	261	$	11,769	$	(5,601)	$	(3,190)	$	16	$	3,255	$	1,210	$	4,465
Net loss attributable to common stock	—		—		—		(4,866)		—		—		(4,866)		—		(4,866)
Net loss attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(162)		(162)
Net loss attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		(9)		(9)

Net income attributable to Altus Preferred Unit holders	37		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(40)		(40)
Common dividends declared ($0.025 per share)	—		—		(19)		—		—		—		(19)		—		(19)
Other	—		1		(6)		—		1		(1)		(5)		—		(5)
Balance at June 30, 2020	$	592	$	262	$	11,744	$	(10,467)	$	(3,189)	$	15	$	(1,635)	$	999	$	(636)

For the Six Months Ended June 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	—		—		—		704		—		—		704		—		704
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		83		83
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		28		28
Net income attributable to Altus Preferred Unit limited partners	43		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(11)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	(23)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(60)		(60)
Common dividends declared ($0.025 per share)	—		—		(19)		—		—		—		(19)		—		(19)
Other	—		—		(12)		—		1		1		(10)		(5)		(15)
Balance at June 30, 2021	$	617	$	262	$	11,704	$	(9,757)	$	(3,188)	$	15	$	(964)	$	1,040	$	76

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

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

During the second quarter of 2020, the Company recorded asset impairments totaling $20 million in connection with fair value assessments on proved property in Egypt. These properties were impaired to their estimated fair values as a result of changes to planned development activity.

During the first quarter of 2020, the Company recorded asset impairments totaling $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 based on the net book value of its assets as of March 31, 2020. The Company recognized proved property impairments totaling $3.9 billion, $354 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. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

During the first quarter of 2020, the Company also recognized impairments of $13 million for the early termination of drilling rig leases and $5 million for inventory revaluations, both in the U.S.

During the first quarter of 2020, the Company 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Proved Properties:
U.S.	$	—	$	—	$	—	$	3,938
Egypt	—		20		—		374
North Sea	—		—		—		7
Total proved properties	$	—	$	20	$	—	$	4,319

Unproved Properties:
U.S.	$	1	$	29	$	17	$	46
Egypt	2		2		4		4

Total unproved properties	$	3	$	31	$	21	$	50

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

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

Gathering, Processing, and Transmission Facilities

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

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

The Company assessed its long-lived infrastructure assets for impairment at 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 six months ended June 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 $993 million and $670 million as of June 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)











Production revenues from customers	$	1,407	$	715	$	2,732	$	1,903





Production revenues from non-customers	107		(18)		213		30
Total production revenues	$	1,514	$	697	$	2,945	$	1,933

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

Transaction, Reorganization, and Separation (TRS)

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

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

2. ACQUISITIONS AND DIVESTITURES

2021 Activity

During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million, for cash proceeds of $178 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $65 million in connection with the sale.

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

2020 Activity

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

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

Suriname Joint Venture Agreement

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

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

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

3. CAPITALIZED EXPLORATORY WELL COSTS

The Company’s capitalized exploratory well costs were $260 million and $197 million as of June 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, as well as transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company also utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of June 30, 2021, 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 changes in commodity prices, currency exchange rates, or interest rates.

Derivative Instruments

Commodity Derivative Instruments

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

Fixed-Price Swaps

Production Period

Settlement Index

Mbbls

Weighted Average Fixed Price

July—September 2021

NYMEX WTI

2,024

$60.15

October—December 2021

NYMEX WTI

1,012

$58.59

July—September 2021

Dated Brent

1,656

$63.08

October—December 2021

Dated Brent

828

$61.44

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

Production Period

Settlement Index

Mbbls

Weighted Average Price Differential

July—September 2021

Midland-WTI/Cushing-WTI

2,024

$0.61

October—December 2021

Midland-WTI/Cushing-WTI

1,012

$0.70

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


		Basis Swap Purchased		Basis Swap Sold
Production Period	Settlement Index	MMBtu (in 000’s)	Weighted Average Price Differential	MMBtu (in 000’s)	Weighted Average Price Differential
July—December 2021	NYMEX Henry Hub/IF Waha	23,930	$(0.42)	—	—
July—December 2021	NYMEX Henry Hub/IF HSC	—	—	23,930	$(0.07)
January—December 2022	NYMEX Henry Hub/IF Waha	43,800	$(0.45)	—	—
January—December 2022	NYMEX Henry Hub/IF HSC	—	—	43,800	$(0.08)
January—December 2023	NYMEX Henry Hub/IF Waha	29,200	$(0.40)	—	—
January—December 2023	NYMEX Henry Hub/IF HSC	—	—	29,200	$0.02

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 1 2 —Redeemable Noncontrolling Interest - Altus.

Pipeline Capacity Embedded Derivatives

During the fourth quarter of 2019 and first quarter of 2020, the Company entered into separate agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements are arrangements 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. These features require bifurcation and measurement of the change in market values for each period. Unrealized gains or losses in the fair value of these features are recorded as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received will be deferred and reflected in income over the original tenure of the transportation agreement.

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)
June 30, 2021
Assets:
Commodity derivative instruments	$	—	$	2	$	—	$	2	$	—	$	2
Liabilities:
Commodity derivative instruments	—		64		—		64		—		64
Pipeline capacity embedded derivatives	—		50		—		50		—		50
Preferred Units embedded derivative	—		—		125		125		—		125

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

Quantitative Information About Level 3 Fair Value Measurements

Fair Value as of June 30, 2021

Valuation Technique

Significant Unobservable Inputs

Range/Value

(In millions)

Preferred Units embedded derivative

125

Option Model

Altus’ Imputed
Interest Rate

5.62-11.50%

Interest Rate
Volatility

38.33%

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

Derivative Activity Recorded in the Consolidated Balance Sheet

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


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

Current Liabilities: Other current liabilities	$	58	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	181		192
Total derivative liabilities	$	239	$	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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Realized:
Commodity derivative instruments	$	(48)	$	(36)	$	100	$	(36)
Foreign currency derivative instruments	—		(1)		—		(1)
Realized gain (loss), net	(48)		(37)		100		(37)
Unrealized:
Commodity derivative instruments	(98)		(111)		(72)		(94)
Pipeline capacity embedded derivatives	2		(17)		3		(70)
Foreign currency derivative instruments	—		1		—		(4)
Preferred units embedded derivative	31		(11)		14		(73)
Unrealized loss, net	(65)		(138)		(55)		(241)
Derivative instrument gains (losses), net	$	(113)	$	(175)	$	45	$	(278)

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

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

5. OTHER CURRENT ASSETS

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


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

Prepaid assets and other	75		71
Total Other current assets	$	628	$	676

6. EQUITY METHOD INTERESTS

As of June 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	June 30, 2021		December 31, 2020
		(In millions)
Gulf Coast Express Pipeline, LLC	16.0%	$	278	$	284
EPIC Crude Holdings, LP	15.0%	167		176
Permian Highway Pipeline, LLC	26.7%	635		615
Shin Oak Pipeline (Breviloba, LLC)	33.0%	474		480
Total Altus equity method interests		$	1,554	$	1,555

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

The following table presents the activity in Altus’ equity method interests for the six months ended June 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	—		1		23		—		24
Distributions	(25)		—		(30)		(21)		(76)

Equity income (loss), net	19		(11)		27		15		50
Accumulated other comprehensive income	—		1		—		—		1
Balance at June 30, 2021	$	278	$	167	$	635	$	474	$	1,554

Summarized Combined Financial Information

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


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

7. OTHER CURRENT LIABILITIES

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


	June 30, 2021		December 31, 2020
	(In millions)
Accrued operating expenses	$	116	$	91
Accrued exploration and development	166		167
Accrued compensation and benefits	147		170
Accrued interest	125		140
Accrued income taxes	68		25
Current asset retirement obligation	56		56
Current operating lease liability	102		116
Current portion of derivatives at fair value	58		—
Other	117		97
Total Other current liabilities	$	955	$	862

8. ASSET RETIREMENT OBLIGATION

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


	June 30, 2021
	(In millions)
Asset retirement obligation, December 31, 2020	$	1,944
Liabilities incurred	3
Liabilities settled	(10)
Liabilities divested	(44)

Accretion expense	56

Asset retirement obligation, June 30, 2021	1,949
Less current portion	(56)
Asset retirement obligation, long-term	$	1,893

9. DEBT AND FINANCING COSTS

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


	June 30, 2021		December 31, 2020
	(In millions)
Apache notes and debentures before unamortized discount and debt issuance costs(1)	$	8,030	$	8,052
Altus credit facility(2)	657		624
Apache credit facility(2)	—		150
Apache finance lease obligations	36		38
Unamortized discount	(34)		(35)
Debt issuance costs	(54)		(57)
Total debt	8,635		8,772
Current maturities	(215)		(2)
Long-term debt	$	8,420	$	8,770

(1) The fair values of the Apache notes and debentures were $8.5 billion as of June 30, 2021 and December 31, 2020. The Company uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

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

As of June 30, 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 six months ended June 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 June 30, 2021. The facility is for general corporate purposes. As of June 30, 2021, there were no borrowings and an aggregate £561 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 June 30, 2021 and December 31, 2020. Apache did not use its commercial paper program during 2021 and terminated the program.

Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, 2021 and 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 June 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	110	$	107	$	222	$	214
Amortization of debt issuance costs	3		2		5		4
Capitalized interest	(2)		(2)		(4)		(6)
Gain on extinguishment of debt	(1)		(140)		(1)		(140)
Interest income	(3)		(1)		(5)		(3)
Financing costs, net	$	107	$	(34)	$	217	$	69

10. INCOME TAXES

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

During the second quarter and the first six months of 2021, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the second 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 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. As of June 30, 2021, the Company has an accrued liability of approximately $71 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. Some of the cases have been remanded to state court with the remand orders being appealed. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas 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. The Company is evaluating appeal.

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 in excess of $250 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. 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. On June 7, 2021, another lawsuit, captioned Thomas Miskella, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. On June 25, 2021, another lawsuit, captioned Rawley Brodeen, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. And on July 14, 2021, another lawsuit, captioned Barry Dudenhoeffer, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al., was filed in the United States District Court for the Southern District of Texas (Houston Division) alleging nearly identical allegations. The defendants believe the plaintiffs’ derivative claims lack merit and intend to vigorously defend these lawsuits.

Environmental Matters

As of June 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 responding to the information request. The EPA has not commenced enforcement proceedings, and at this time, the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and responding to the information request. The EPA has not commenced enforcement proceedings, and at this time, the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

The Company is not aware of any environmental claims existing as of June 30, 2021 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Asset Retirement Obligations

In 2013, the Company sold its Gulf of Mexico (GOM) Shelf operations and properties (Legacy GOM Assets) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the Company received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date. In respect of such abandonment liabilities, Fieldwood posted letters of credit in favor of the Company (Letters of Credit) and established a trust account (Trust A), which is funded by a 10 percent net profits interest depending on future oil prices and of which the Company is the beneficiary. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which the Company agreed, inter alia, to accept bonds in exchange for certain of the Letters of Credit. Currently, the Company holds two bonds (Bonds) and the remaining Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Legacy GOM Assets as and when such abandonment and decommissioning obligations are required to be performed over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Legacy GOM Assets into a standalone company, and proceeds of production of the Legacy GOM Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then the Company expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, the Company has agreed to provide a standby loan of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.

On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan.

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	—	(23)
Distributions payable to Altus Preferred Unit limited partners	—	(11)
Allocation of Altus Midstream LP net income	N/A	39
Accreted value adjustment	N/A	4
Redeemable noncontrolling interest — Preferred Unit at: June 30, 2021	660,694	617
Preferred Units embedded derivative		125
		$	742

(1) The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of June 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 June 30, 2021, the Redemption Price would have been based on a 1.3 times multiple of invested capital, which was $813 million, less certain cash distributions. This was greater than using an 11.5 percent internal rate of return, which would equate to a redemption value of $721 million.

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

	For the Six Months Ended June 30,
	2021					2020
	Income		Shares	Per Share		Loss		Shares	Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	704	378	$	1.86	$	(4,866)	378	$	(12.88)
Effect of Dilutive Securities:
Stock options and other	$	—	1	$	—	$	—	—	$	—
Diluted:
Income (loss) attributable to common stock	$	704	379	$	1.86	$	(4,866)	378	$	(12.88)

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 June 30, 2020 and for each of the six months ended June 30, 2021 and 2020. The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive of 3.4 million and 5.2 million during the second quarters of 2021 and 2020, respectively, and 3.7 million and 5.4 million during the first six months of 2021 and 2020, respectively.

Stock Repurchase Program

In 2013 and 2014, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock, and during the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through June 30, 2021, has repurchased a total of 40 million shares at an average price of $79.18 per share. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the six months ended June 30, 2021.

Common Stock Dividends

For the quarter ended June 30, 2021 and 2020, the Company paid $9 million and $10 million, respectively, in dividends on its common stock. For the six months ended June 30, 2021 and 2020, the Company paid $19 million and $104 million, respectively, in 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 to $0.025, effective for all dividends payable after March 12, 2020.

14. BUSINESS SEGMENT INFORMATION

As of June 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(1)
	Upstream
For the Quarter Ended June 30, 2021	(In millions)
Revenues:
Oil revenues	$	432	$	216	$	493	$	—	$	—	$	1,141
Natural gas revenues	65		27		134		—		—		226
Natural gas liquids revenues	2		4		141		—		—		147
Oil, natural gas, and natural gas liquids production revenues	499		247		768		—		—		1,514
Purchased oil and gas sales	—		—		239		3		—		242
Midstream service affiliate revenues	—		—		—		32		(32)		—
	499		247		1,007		35		(32)		1,756
Operating Expenses:
Lease operating expenses	114		98		99		—		—		311
Gathering, processing, and transmission	3		8		74		8		(32)		61
Purchased oil and gas costs	—		—		259		3		—		262
Taxes other than income	—		—		47		4		—		51
Exploration	14		3		2		—		7		26
Depreciation, depletion, and amortization	137		63		148		3		—		351
Asset retirement obligation accretion	—		20		7		1		—		28

	268		192		636		19		(25)		1,090
Operating Income (Loss)(2)	$	231	$	55	$	371	$	16	$	(7)	666

Other Income (Expense):
Derivative instrument gains, net											(113)
Gain on divestitures, net											65
Other											74
General and administrative											(86)
Transaction, reorganization, and separation											(4)
Financing costs, net											(107)
Income Before Income Taxes											$	495


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

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

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

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


	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(1)
	Upstream
For the Quarter Ended June 30, 2020	(In millions)
Revenues:
Oil revenues	$	187	$	128	$	198	$	—	$	—	$	513
Natural gas revenues	70		7		53		—		—		130
Natural gas liquids revenues	1		3		50		—		—		54
Oil, natural gas, and natural gas liquids production revenues	258		138		301		—		—		697
Purchased oil and gas sales	—		—		54		1		—		55
Midstream service affiliate revenues	—		—		—		31		(31)		—
	258		138		355		32		(31)		752
Operating Expenses:
Lease operating expenses	98		75		90		—		1		264
Gathering, processing, and transmission	13		11		70		10		(32)		72
Purchased oil and gas costs	—		—		46		—		—		46
Taxes other than income	—		—		20		3		—		23
Exploration	22		15		31		—		4		72
Depreciation, depletion, and amortization	158		79		178		3		—		418
Asset retirement obligation accretion	—		18		8		1		—		27
Impairments	20		—		—		—		—		20
	311		198		443		17		(27)		942
Operating Income (Loss)(2)	$	(53)	$	(60)	$	(88)	$	15	$	(4)	(190)

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

Other											19
General and administrative											(94)
Transaction, reorganization, and separation											(10)
Financing costs, net											34
Loss Before Income Taxes											$	(416)


	Egypt		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(1)
	Upstream
For the Six Months Ended June 30, 2020	(In millions)
Revenues:
Oil revenues	$	520	$	399	$	626	$	—	$	—	$	1,545
Natural gas revenues	135		26		92		—		—		253
Natural gas liquids revenues	4		10		121		—		—		135
Oil, natural gas, and natural gas liquids production revenues	659		435		839		—		—		1,933
Purchased oil and gas sales	—		—		162		1		—		163
Midstream service affiliate revenues	—		—		—		72		(72)		—
	659		435		1,001		73		(72)		2,096
Operating Expenses:
Lease operating expenses	210		156		233		—		—		599
Gathering, processing, and transmission	23		27		145		20		(72)		143
Purchased oil and gas costs	—		—		131		1		—		132
Taxes other than income	—		—		49		7		—		56
Exploration	40		17		66		—		6		129
Depreciation, depletion, and amortization	319		188		471		6		—		984
Asset retirement obligation accretion	—		36		16		2		—		54
Impairments	529		7		3,956		—		—		4,492
	1,121		431		5,067		36		(66)		6,589
Operating Income (Loss)(2)	$	(462)	$	4	$	(4,066)	$	37	$	(6)	(4,493)

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

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

(1) Includes noncontrolling interests in Egypt and Altus.

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

(3) Intercompany balances are excluded from total assets.

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 second quarter of 2021, the Company reported net income of $316 million, or $0.82 per diluted common share, compared to a loss of $386 million, or $1.02 per diluted common share, in the second quarter of 2020. The increase in net income compared to the prior-year period is primarily the result of significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic began to negatively affect economic activity and the oil markets. In response to lower commodity prices, the Company materially reduced its upstream capital investment budget and drilling activity during the first half of 2020. Daily production decreased 9 percent from an average of 435 Mboe/d in the second quarter of 2020 to an average of 395 Mboe/d in the second quarter of 2021.

The Company generated $1.6 billion of cash from operating activities during the first six months of 2021, a 180 percent increase from the first six months of 2020 driven by higher commodity prices and associated revenues. The Company ended the quarter with $1.2 billion of cash.

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 second 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. For the second quarter, the Company placed 27 wells online in the Permian Basin, including five at Alpine High. Three wells were drilled in the Austin Chalk where the results are continuing to be evaluated. The Company is assessing the addition of a third rig in the U.S., which would provide a path to sustained oil production.

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

•The Company averaged six drilling rigs in Egypt and completed 15 wells during the first half of 2021. Second-quarter gross equivalent production in the Company’s Egypt assets decreased 17 percent from the second 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 PSC agreement, the Company expects to further increase drilling and workover activity.

•The Company averaged two rigs in the North Sea during the second quarter of 2021. Production from the Forties field was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages during the first half of the year. Further impacts are expected in the third quarter of 2021 from continued operational downtime and planned platform maintenance turnarounds on the Beryl platforms.

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

•In July 2021, the Company announced drilling success at Sapakara South-1, an appraisal well located on the eastern edge of the Sapakara area, which encountered approximately 30 meters of net black oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. The Maersk Valiant drillship will soon mobilize to the Bonboni exploration prospect in the northern portion of Block 58 before returning later in the year to flow test Sapakara South-1. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding a 50 percent working interest.

Results of Operations

Oil and Gas Production Revenues

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


	For the Quarter Ended June 30,								For the Six Months Ended June 30,
	2021				2020				2021				2020
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	493	43	%	$	198	39	%	$	841	39	%	$	626	41	%
Egypt(1)	432		38	%	187		36	%	834		39	%	520		33	%
North Sea	216		19	%	128		25	%	457		22	%	399		26	%
Total(1)	$	1,141	100	%	$	513	100	%	$	2,132	100	%	$	1,545	100	%

Natural Gas Revenues:
United States	$	134	59	%	$	53	41	%	$	345	64	%	$	92	36	%
Egypt(1)	65		29	%	70		54	%	135		25	%	135		54	%
North Sea	27		12	%	7		5	%	58		11	%	26		10	%
Total(1)	$	226	100	%	$	130	100	%	$	538	100	%	$	253	100	%

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

Oil and Gas Revenues:
United States	$	768	51	%	$	301	43	%	$	1,447	49	%	$	839	43	%
Egypt(1)	499		33	%	258		37	%	973		33	%	659		34	%
North Sea	247		16	%	138		20	%	525		18	%	435		23	%
Total(1)	$	1,514	100	%	$	697	100	%	$	2,945	100	%	$	1,933	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 June 30,			For the Six Months Ended, June 30,
	2021	Increase (Decrease)	2020	2021	Increase (Decrease)	2020
Oil Volume (b/d)
United States	82,852	(12)%	94,471	75,313	(23)%	98,042
Egypt(1)(2)	71,182	(11)%	79,839	71,673	(6)%	76,509
North Sea	31,992	(32)%	47,016	37,726	(26)%	51,139
Total	186,026	(16)%	221,326	184,712	(18)%	225,690

Natural Gas Volume (Mcf/d)
United States	541,088	4%	518,156	524,396	(6)%	557,999
Egypt(1)(2)	256,262	(8)%	279,561	267,145	—%	267,070
North Sea	36,769	(30)%	52,612	43,268	(28)%	59,945
Total	834,119	(2)%	850,329	834,809	(6)%	885,014

NGL Volume (b/d)
United States	68,492	(2)%	69,759	63,183	(16)%	75,570
Egypt(1)(2)	553	(39)%	909	568	(38)%	914
North Sea	1,095	(37)%	1,733	1,231	(36)%	1,934
Total	70,140	(3)%	72,401	64,982	(17)%	78,418

BOE per day(3)
United States	241,525	(4)%	250,589	225,895	(15)%	266,612
Egypt(1)(2)	114,445	(10)%	127,342	116,765	(4)%	121,934
North Sea(4)	39,216	(32)%	57,517	46,169	(27)%	63,064
Total	395,186	(9)%	435,448	388,829	(14)%	451,610

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


	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2021	2020	2021	2020
Oil (b/d)	135,494	171,897	135,408	177,762
Natural Gas (Mcf/d)	578,380	642,003	590,756	648,706
NGL (b/d)	866	1,649	881	1,715

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


	For the Quarter Ended June 30,		For the Six Months Ended June 30,
	2021	2020	2021	2020
Oil (b/d)	23,759	26,609	23,923	25,604
Natural Gas (Mcf/d)	85,574	92,625	89,235	89,148
NGL (b/d)	184	303	189	304

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

(4) Average sales volumes from the North Sea for the second quarter of 2021 and 2020 were 41,941 boe/d and 54,996 boe/d, respectively, and 48,208 boe/d and 64,133 boe/d for the first six 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 June 30,					For the Six Months Ended, June 30,
	2021		Increase (Decrease)	2020		2021		Increase (Decrease)	2020
Average Oil Price - Per barrel
United States	$	65.32	184%	$	23.02	$	61.68	76%	$	35.09
Egypt	66.70		159%	25.80		64.30		72%	37.36
North Sea	68.34		117%	31.55		63.48		51%	41.94
Total	66.40		158%	25.77		63.06		68%	37.44

Average Natural Gas Price - Per Mcf
United States	$	2.73	142%	$	1.13	$	3.63	303%	$	0.90
Egypt	2.80		3%	2.73		2.80		1%	2.78
North Sea	8.10		466%	1.43		7.43		208%	2.41
Total	2.99		78%	1.68		3.56		127%	1.57

Average NGL Price - Per barrel
United States	$	22.72	191%	$	7.81	$	22.84	160%	$	8.77
Egypt	38.10		82%	20.97		41.49		57%	26.36
North Sea	38.79		91%	20.35		44.21		51%	29.29
Total	23.10		179%	8.28		23.41		147%	9.48

Second-Quarter 2021 compared to Second-Quarter 2020

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

Natural Gas Gas revenues for the second quarter of 2021 totaled $226 million, a $96 million increase from the comparative 2020 quarter. A 78 percent increase in average realized prices increased second-quarter 2021 natural gas revenues by $100 million compared to the prior-year quarter, while 2 percent lower average daily production decreased revenues by $4 million. Natural gas revenues accounted for 15 percent of total oil and gas production revenues and 35 percent of worldwide production during the second quarter of 2021. The Company’s worldwide natural gas production decreased 16 MMcf/d to 834 MMcf/d during the second 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 second quarter of 2021 totaled $147 million, a $93 million increase from the comparative 2020 quarter. A 179 percent increase in average realized prices increased second-quarter 2021 NGL revenues by $98 million compared to the prior-year quarter, while 3 percent lower average daily production decreased revenues by $5 million. NGL revenues accounted for 10 percent of total oil and gas production revenues and 18 percent of worldwide production during the second quarter of 2021. The Company’s worldwide NGL production decreased 2.3 Mb/d to 70.1 Mb/d during the second 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 six months of 2021 totaled $2.1 billion, a $0.6 billion increase from the comparative 2020 period. A 68 percent increase in average realized prices increased 2021 oil revenues by $1.1 billion compared to the prior-year period, while 18 percent lower average daily production decreased revenues by $471 million. Crude oil revenues accounted for 73 percent of total oil and gas production revenues and 47 percent of worldwide production for the first six months of 2021. Crude oil prices realized during the first six months of 2021 averaged $63.06 per barrel, compared to $37.44 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 41.0 Mb/d to 184.7 Mb/d in the first six months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, extended operational downtime, and extended platform turnaround work in the North Sea.

Natural Gas Gas revenues for the first six months of 2021 totaled $538 million, a $285 million increase from the comparative 2020 period. A 127 percent increase in average realized prices increased 2021 natural gas revenues by $321 million compared to the prior-year period, while 6 percent lower average daily production decreased revenues by $36 million. Natural gas revenues accounted for 18 percent of total oil and gas production revenues and 36 percent of worldwide production for the first six months of 2021. Natural gas prices realized during the first six months of 2021 averaged $3.56 per Mcf, compared to $1.57 per Mcf in the comparative prior-year period. Gas prices for the U.S. during the first six months of 2021 also reflect the extreme price volatility during the month of February due to the Texas freeze event. The Company’s worldwide natural gas production decreased 50 MMcf/d to 835 MMcf/d in the first six 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 six months of 2021 totaled $275 million, a $140 million increase from the comparative 2020 period. A 147 percent increase in average realized prices increased 2021 NGL revenues by $199 million compared to the prior-year period, while 17 percent lower average daily production decreased revenues by $59 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production for the first six months of 2021. NGL prices realized during the first six months of 2021 averaged $23.41 per barrel, compared to $9.48 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased 13.4 Mb/d to 65.0 Mb/d in the first six 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 $32 million and $31 million during the second quarters of 2021 and 2020, respectively, and $64 million and $72 million during the first six 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 fluctuations in natural gas throughput volumes processed by Altus for the Company’s Alpine High production.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $242 million and $55 million during the second quarters of 2021 and 2020, respectively, and $682 million and $163 million during the first six months of 2021 and 2020, respectively. Purchased oil and gas sales were offset by associated purchase costs of $262 million and $46 million during the second quarters of 2021 and 2020, respectively, and $756 million and $132 million during the first six 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 second quarter and first six months of 2021 increased as a result of production shortfalls following reduced capital investment and drilling activity in 2020. The year-to-date net loss was exacerbated by extreme price volatility 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Lease operating expenses	$	311	$	264	$	575	$	599
Gathering, processing, and transmission	61		72		119		143
Purchased oil and gas costs	262		46		756		132
Taxes other than income	51		23		95		56
Exploration	26		72		75		129
General and administrative	86		94		169		162
Transaction, reorganization, and separation	4		10		4		37
Depreciation, depletion, and amortization:
Oil and gas property and equipment	322		387		634		918
Gathering, processing, and transmission assets	19		19		38		39
Other assets	10		12		21		27
Asset retirement obligation accretion	28		27		56		54
Impairments	—		20		—		4,492
Financing costs, net	107		(34)		217		69
Total Operating Expenses	$	1,287	$	1,012	$	2,759	$	6,857

Lease Operating Expenses (LOE)

LOE increased $47 million and decreased $24 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 28 percent and 12 percent in the second quarter and the first six 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 second 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 June 30,				For the Six Months Ended, June 30,
	2021		2020		2021		2020
	(In millions)
Third-party processing and transmission costs	$	53	$	62	$	104	$	123
Midstream service affiliate costs	32		32		63		72
Upstream processing and transmission costs	85		94		167		195
Midstream operating expenses	8		10		15		20
Intersegment eliminations	(32)		(32)		(63)		(72)
Total Gathering, processing, and transmission	$	61	$	72	$	119	$	143

GPT costs decreased $11 million and $24 million in the second quarter and the first six months 2021, respectively, from the comparative prior-year periods. Third-party processing and transmission costs decreased $9 million and $19 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs remained flat in the second quarter of 2021 and decreased $9 million in the first six months of 2021, compared to their respective prior-year periods. The overall decrease in the first six months of 2021 was primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, decreased $2 million and $5 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.

Purchased Oil and Gas Costs

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

Taxes Other Than Income

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

Exploration Expenses

The Company’s exploration expenses were as follows:


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

Exploration expenses decreased $46 million and $54 million from the second quarter and the first six months of 2020, respectively, primarily the result of lower dry hole expense and exploration overhead, a function of decreased exploration activities. The Company also had lower unproved leasehold impairments driven by improved commodity prices.

General and Administrative (G&A) Expenses

G&A expenses decreased $8 million in the second quarter of 2021 compared to the second quarter of 2020, and increased $7 million in the first six months of 2021 compared to the first six months of 2020. The reduction in second-quarter 2021 G&A compared to the prior-year quarter was driven by organizational redesign efforts during 2019 and 2020. The increase in the first six months of 2021 from the comparative prior-year period was primarily related to higher cash-based stock compensation expense resulting from an increase in the Company’s stock price, offset by lower overhead during the year as previously discussed.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $6 million and $33 million from the second quarter and the first six months of 2020, respectively, driven by costs associated with the Company’s reorganization efforts incurred 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 $65 million and $284 million from the second quarter and the first six months of 2020, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.93 per boe and $2.18 per boe from the second quarter and the first six months of 2020, respectively. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT assets remained essentially flat compared to the second quarter and the first six months of 2020.

Impairments

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

The Company recognized $4.5 billion in asset impairments in connection with fair value assessments during the first six months of 2020. During the second quarter of 2020, the Company recognized impairments totaling $20 million related to proved oil and gas properties in Egypt. During the first quarter of 2020, the Company recognized impairments totaling $4.3 billion related to proved oil and gas properties in the U.S., Egypt, and the North Sea, $68 million related to GPT 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 June 30,				For the Six Months Ended, June 30,
	2021		2020		2021		2020
	(In millions)
Interest expense	$	110	$	107	$	222	$	214
Amortization of debt issuance costs	3		2		5		4
Capitalized interest	(2)		(2)		(4)		(6)
Gain on extinguishment of debt	(1)		(140)		(1)		(140)
Interest income	(3)		(1)		(5)		(3)
Total Financing costs, net	$	107	$	(34)	$	217	$	69

Net financing costs increased $141 million and $148 million from the second quarter and the first six months of 2020, respectively, driven by the $140 million gain on extinguishment of debt recorded in the second quarter of 2020.

Provision for Income Taxes

During the second quarter and the first six months of 2021, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the second quarter and first six months of 2020, the Company’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets and impairments recorded during the period. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets.

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

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 second 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 of Apache Corporation 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 Six Months Ended June 30,
	2021		2020
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	1,640	$	586
Proceeds from Apache credit facility, net	—		565
Proceeds from Altus credit facility, net	33		97
Proceeds from asset divestitures	181		126


Total Sources of Cash and Cash Equivalents	1,854		1,374
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property(1)	$	(558)	$	(838)
Additions to Altus gathering, processing, and transmission facilities(1)	(1)		(25)
Leasehold and property acquisitions	(3)		(3)
Contributions to Altus equity method interests	(24)		(154)

Payments on Apache credit facility, net	(150)		—
Payments on fixed-rate debt	(20)		(264)
Dividends paid to APA common stockholders	(19)		(104)
Distributions to noncontrolling interest - Egypt	(60)		(40)
Distributions to Altus Preferred Unit limited partners	(23)		—
Other	(9)		(58)
Total Uses of Cash and Cash Equivalents	(867)		(1,486)
Increase (decrease) in cash and cash equivalents	$	987	$	(112)

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

Sources of Cash and Cash Equivalents

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

Net cash provided by operating activities increased $1.1 billion from the first six 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 six months of 2020, Apache borrowed $565 million under its revolving credit facility.

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity method pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first six months of 2021 and 2020, Altus Midstream LP borrowed $33 million and $97 million, respectively, under its revolving credit facility to meet this short fall. With 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 $181 million and $126 million of proceeds from the divestiture of certain non-core assets during the first six 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 $558 million and $838 million during the first six 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. The Company operated an average of 10 drilling rigs during the second quarter of 2021, compared to an average of 12 drilling rigs during the second quarter of 2020.

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

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

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

Payments on Apache Credit Facility Apache paid $150 million during the first six months of 2021 on its revolving credit facility borrowings.

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

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

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

Dividends The Company paid $19 million and $104 million during the first six 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.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $60 million and $40 million during the first six months of 2021 and 2020, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $23 million during the first six months of 2021 in cash distributions to its limited partners holding Preferred Units. No cash distributions were made during the first six months of 2020. 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:


	June 30, 2021		December 31, 2020
	(In millions)
Cash and cash equivalents	$	1,249	$	262
Total debt - Apache	7,978		8,148
Total debt - Altus	657		624
Total equity (deficit)	76		(645)
Available committed borrowing capacity - Apache	3,204		2,944
Available committed borrowing capacity - Altus	141		176

Cash and Cash Equivalents As of June 30, 2021, the Company had $1.2 billion in cash and cash equivalents, of which approximately $75 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 June 30, 2021, the Company had $8.6 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. As of June 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 June 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 June 30, 2021, there were no borrowings and aggregate £561 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 June 30, 2021.

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

Commercial Paper Program Apache has not used its commercial paper program during 2021 and terminated the program. As of June 30, 2021 and December 31, 2020, 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 Asset Retirement Obligations

The Company has 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 the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of the Company’s GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA could be required to perform such actions under applicable federal laws and regulations. In such event, APA may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, the Company sold its GOM Shelf operations and properties (Legacy GOM Assets) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the Company received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date. In respect of such abandonment liabilities, Fieldwood posted letters of credit in favor of the Company (Letters of Credit) and established a trust account (Trust A), which is funded by a 10 percent net profits interest depending on future oil prices and of which the Company is the beneficiary. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which the Company agreed, inter alia, to accept bonds in exchange for certain of the Letters of Credit. Currently, the Company holds two bonds (Bonds) and the remaining Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Legacy GOM Assets as and when such abandonment and decommissioning obligations are required to be performed over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Legacy GOM Assets into a standalone company, and proceeds of production of the Legacy GOM Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then the Company expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, the Company has agreed to provide a standby loan of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.

On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan.

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 realizations increased 158 percent from $25.77 per barrel to $66.40 per barrel during the second quarters of 2020 and 2021, respectively. The Company’s average natural gas price realizations increased 78 percent from $1.68 per Mcf to $2.99 per Mcf during the second quarters of 2020 and 2021, respectively. The Company’s average NGL realizations increased 179 percent from $8.28 per barrel to $23.10 per barrel during the second quarters of 2020 and 2021, respectively. Based on average daily production for the second 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 $17 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6 million.

The Company periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of June 30, 2021, the Company had open natural gas derivatives not designated as cash flow hedges in a liability position with a fair value of less than $1 million. A 10 percent increase in gas prices would increase the liability by approximately $3 million, while a 10 percent decrease in gas prices would move the derivatives to an asset position of $3 million. As of June 30, 2021, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $62 million. A 10 percent increase in oil prices would increase the liability by approximately $57 million, while a 10 percent decrease in oil prices would decrease the liability by approximately $57 million. These fair value changes assume volatility based on prevailing market parameters at June 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 June 30, 2021, the Company had $8.0 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 4.98 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt. The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the indentures and credit facilities. As of June 30, 2021, the Company had approximately $1.2 billion in cash and cash equivalents, approximately 72 percent of which was invested in money market funds and short-term investments with major financial institutions. As of June 30, 2021, Altus Midstream LP had outstanding borrowings of $657 million under its revolving credit facility. 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 $6 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 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 June 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 June 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 June 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 and June 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 and June 30, 2021.

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

In 2013 and 2014, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock, and during the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through June 30, 2021, had repurchased a total of 40 million shares at an average price of $79.18 per share. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the first six months of 2021.

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 March 1, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K dated March 1, 2021, SEC File No. 001-40144).
*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 June 30, 2021, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interest and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags.
*101.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:	August 5, 2021	/s/ STEPHEN J. RINEY
		Stephen J. Riney
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

Dated:	August 5, 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: August 5, 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: August 5, 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 June 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: August 5, 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 June 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: August 5, 2021


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