10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2021

or 

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

For the transition period from            to                 

Commission file number 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter) 

Delaware	41-0747868
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (713) 296-6000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☒ No ☐

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

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

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2021	N/A
Number of shares of registrant’s common stock outstanding as of January 31, 2022 (100% owned by APA Corporation)	1,000

OMISSION OF CERTAIN INFORMATION

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of APA Corporation’s proxy statement relating to its 2022 annual meeting of stockholders (the APA Proxy Statement) have been incorporated by reference into Part III hereof.

TABLE OF CONTENTS

Item		Page
	PART I
1.	BUSINESS	1
1A.	RISK FACTORS	14
1B.	UNRESOLVED STAFF COMMENTS	27
2.	PROPERTIES	1
3.	LEGAL PROCEEDINGS	27
4.	MINE SAFETY DISCLOSURES	27
	PART II
5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER  MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	28
6.	SELECTED FINANCIAL DATA	28
7.	MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS	29
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	45
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	45
9A.	CONTROLS AND PROCEDURES	45
9B.	OTHER INFORMATION	46
9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	46
	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	47
11.	EXECUTIVE COMPENSATION	47
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	47
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	47
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	47
	PART IV
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	48
16.	FORM 10-K SUMMARY	51

i

FORWARD-LOOKING STATEMENTS AND RISKS

This Annual Report on Form 10-K 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 Annual Report on Form 10-K, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2021, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:

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

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

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

•the Company’s commodity hedging arrangements;

•the supply and demand for oil, natural gas, NGLs, and other products or services;

•production and reserve levels;

•drilling risks;

•economic and competitive conditions;

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the availability of goods and services;

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

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

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

•terrorism or cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

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

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

•the Company’s expectations with respect to the new operating structure implemented pursuant to the Holding Company Reorganization (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K) and the associated disclosure implications; and

ii

•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 this Annual Report on Form 10-K.

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 Annual Report on Form 10-K. 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.

ii

DEFINITIONS

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

“3-D” means three-dimensional.

“4-D” means four-dimensional.

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

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

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

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

“boe/d” means boe per day.

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

“Liquids” means oil and NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

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

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

iii

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

iii

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

GENERAL

Apache Corporation, a direct, wholly owned subsidiary of APA Corporation (APA), is an independent energy company that explores for, develops, and produces natural gas, crude oil, and 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). Apache’s midstream business (Altus Midstream) 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.

On March 1, 2021, the Company completed a holding company reorganization (the Holding Company Reorganization), pursuant to which, the Company became a direct, wholly owned subsidiary of APA, and all of the Company’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for more detail.

Through APA’s website, www.apacorp.com, you can access, free of charge, electronic copies of the documents the Company files with the SEC, including the Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, as well as any amendments to these reports. Included in the Company’s annual and quarterly reports are the certifications of its principal executive officer and its principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after the Company files such material with, or furnishes it to, the SEC. You may also request printed copies of the Company’s corporate charter, bylaws, or other governance documents free of charge by writing to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. The Company’s reports filed with the SEC are made available on its website at www.sec.gov. Information on APA’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

Certain properties referred to herein may be held by subsidiaries of Apache Corporation.

BUSINESS OVERVIEW

The following business overview further describes the operations and activities for the Company’s upstream exploration and production properties, by geographic region, and Altus Midstream.

UPSTREAM EXPLORATION AND PRODUCTION

Operating Areas

Apache has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea).

The following table sets out a brief comparative summary of certain key 2021 data for each of Apache’s operating areas. Additional data and discussion are provided in Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

1

	Production	Percentage of Total Production		Production Revenue		Year-End Estimated Proved Reserves	Percentage of Total Estimated Proved Reserves		Gross Wells Drilled	Gross Productive Wells Drilled
	(In MMboe)			(In millions)		(In MMboe)
United States	83.7	59	%	$	3,277	617	68	%	102	102
Egypt(1)	41.9	30	%	2,085		197	21	%	54	39
North Sea(2)	16.0	11	%	1,136		99	11	%	6	4
Total	141.6	100	%	$	6,498	913	100	%	162	145

(1)Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of 2021 production and accounted for 16 percent of year-end estimated proved reserves.

(2)Sales volumes from the Company’s North Sea assets for 2021 were 16.1 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

United States

In 2021, Apache’s U.S. upstream oil and gas operations contributed approximately 59 percent of production and 68 percent of estimated year-end proved reserves, consistent with prior years. Apache has access to significant liquid hydrocarbons across its 3.8 million gross acres (1.8 million net acres) in the U.S., 75 percent of which are undeveloped.

The Company’s U.S. assets are primarily located in the Permian Basin in West Texas and New Mexico, including the Permian sub-basins: Midland Basin, Central Basin Platform/Northwest Shelf, and Delaware Basin. Examples of shale plays being developed within these sub-basins include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry. Apache is one of the largest operators in the Permian Basin, operating approximately 6,000 gross oil and gas wells across its acreage, with additional interests in more than 3,000 non-operated wells. Of note, approximately six percent of the Company’s net acreage position in the Permian Basin is on federal onshore lands. Apache also has operations located in the Eagle Ford shale and Austin Chalk areas of Southeast Texas, offshore in the Gulf of Mexico, and along the Gulf Coast in South Texas and Louisiana.

Highlights of the Company’s operations in the U.S. include:

•Southern Midland Basin Apache holds approximately 332,000 gross acres (238,000 net acres) in the Southern Midland Basin. During 2021, the Company averaged one rig targeting oil plays in the Wolfcamp and Spraberry formations, drilling 49 gross development wells in this basin with a 100 percent success rate.

•Delaware Basin Apache holds approximately 267,000 gross acres (134,000 net acres) in the Delaware Basin, including opportunities in the Bone Spring and other formations of Eastern New Mexico and bordering West Texas, and the Alpine High play in the Southern portion of the Permian Basin, primarily in Reeves County, Texas. During 2021, the Company focused on completing wells drilled from previous years and completed 27 gross development wells.

•Legacy Assets Apache holds approximately 3.2 million gross acres (1.5 million net acres) in legacy properties, of which 1.1 million gross acres are in the offshore waters of the Gulf of Mexico. Legacy onshore properties are located primarily in the Eagle Ford shale and Austin Chalk areas of Southeast Texas. The Company participated in drilling 14 gross non-operated development wells in these areas during 2021. The Company also initiated a targeted drilling program on its Austin Chalk acreage where it will continue to evaluate and high-grade inventory opportunities. Consistent with the Company’s broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings during the year were divested, primarily in the Central Basin Platform subbasin of the Permian Basin, and additional monetization opportunities are continuing to be evaluated.

•New Venture Assets Apache separately has undeveloped acreage positions across several states where it intends to pursue exploration interests and potential development opportunities over time.

•During the fourth quarter of 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals, three months ahead of schedule.

2

With the improvement in commodity prices, the Company is returning to a modest level of activity in the U.S. 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. For 2022, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserves economically.

U.S. Marketing In general, most of the Company’s U.S. natural gas production is sold at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies as well as end-users, marketers, and integrated major oil companies. Apache strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk. Apache predominantly sells its natural gas production within the U.S., including to U.S. LNG export facilities, although a portion may be sold to markets in Mexico.

Apache primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g. WTI Houston, West Texas Sour (WTS), or WTI Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. Apache’s objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts. These term contracts typically have a firm transportation commitment and often provide an opportunity for higher than prevailing market prices.

Apache’s U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require Apache to deliver an average of 251 Bcf of natural gas per year for the period from 2022 through 2029 at variable, market-based pricing and deliver an average of 6.4 MMbbls of crude oil per year from 2022 through 2025 at variable, market-based pricing.

Apache currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development and/or spot market purchases as necessary. Apache may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments.

For more information regarding the Company’s commitments, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations of this Annual Report on Form 10-K.

International

In 2021, international assets contributed 41 percent of Apache’s production and 50 percent of oil and gas revenues. Approximately 32 percent of estimated proved reserves at year-end were located outside the U.S.

Apache has two international locations with ongoing development and production operations:

•Egypt, which includes onshore conventional assets located in Egypt’s Western Desert; and

•the North Sea, which includes offshore assets based in the U.K.

Egypt Apache has 26 years of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt’s Western Desert. At year-end 2021, the Company held 5.3 million gross acres in Egypt in six separate concessions, but primarily held in a new, single concession that resulted from the ratification of a modernized production sharing contract (PSC) with the Egyptian government, as more fully described below. Development leases within concessions currently have expiration dates ranging from 1 to 20 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Approximately 68 percent of the Company’s gross acreage in Egypt is undeveloped, providing Apache with considerable exploration and development opportunities for the future.

3

Apache’s Egypt operations are conducted pursuant to PSCs. Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and are reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on Apache’s Egypt operations despite impacting Apache’s production and reserves.

On December 27, 2021, the Company announced the ratification of a modernized PSC with EGPC having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit sharing rate of 30 percent for all Apache production covered under the new concession. The Apache subsidiary that became the sole Contractor under the PSC is owned by an Apache-operated joint venture owned two-thirds by Apache and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).

The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Through the joint venture, Sinopec holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt. Apache’s Egypt assets, including the one-third noncontrolling interest, contributed 30 percent of 2021 production and 21 percent of year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 22 percent of 2021 production and 16 percent of year-end estimated proved reserves.

In 2021, the Company drilled 30 gross development and 24 gross exploration wells in Egypt. A key component of the Company’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable Apache’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering over 3 million acres to date and 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.

For 2022, the Company plans to increase activity to a 15-rig drilling program for the year and increase well completions by approximately three times compared to 2021 with a goal of growing gross oil production 13 to 15 percent.

North Sea Apache has interests in approximately 494,000 gross acres in the U.K. North Sea. These assets contributed 11 percent of Apache’s 2021 production and approximately 11 percent of year-end estimated proved reserves.

Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, Apache has actively invested in these assets and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of 4-D seismic. Building upon its success in Forties, in 2011 Apache acquired Mobil North Sea Limited, providing the Company with additional exploration and development opportunities in the North Sea across numerous fields, including operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. Apache also has a non-operated interest in the Nelson field acquired in 2011. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. The North Sea assets play a strategic role in Apache’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential, near existing infrastructure.

During 2021, Apache averaged two rigs in the North Sea and drilled 4 gross development and two gross exploration wells. Production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party outage during 2021.

In 2022, the expected capital program for the North Sea remains relatively unchanged from the prior year with one floating rig and one platform crew.

4

International Marketing  Apache’s natural gas production in Egypt is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Crude oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is sold and exported from one of two terminals on the Northern coast of Egypt. Oil production sold to EGPC is sold at prices related to the export market.

Apache’s North Sea crude oil production is sold under term, entitlement volume contracts and spot variable volume contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, operated by Ancala Midstream Acquisitions Limited. Natural gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The condensate mix from the SAGE plant is processed further downstream. The split streams of propane, butane, and condensate are sold separately on a monthly entitlement basis at the Braefoot Bay terminal using index pricing less transportation.

Drilling Statistics

Worldwide in 2021, Apache drilled or participated in drilling 162 gross wells, with 145 wells (90 percent) completed as producers. Historically, Apache’s drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, the Company’s operations outside of the U.S. focus on a mix of exploration and development wells. In addition to wells completed, at year-end a number of wells had not yet reached completion: 53 gross (41.7 net) in the U.S., 22 gross (22.0 net) in Egypt, and 1 gross (1 net) in the North Sea.

The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:

	Net Exploratory			Net Development			Total Net Wells
	Productive	Dry	Total	Productive	Dry	Total	Productive	Dry	Total
2021
United States	—	—	—	67.9	—	67.9	67.9	—	67.9
Egypt	10.0	14.0	24.0	28.5	1.0	29.5	38.5	15.0	53.5
North Sea	0.6	0.5	1.1	1.8	0.5	2.3	2.4	1.0	3.4
Total	10.6	14.5	25.1	98.2	1.5	99.7	108.8	16.0	124.8
2020
United States	—	—	—	46.3	0.8	47.1	46.3	0.8	47.1
Egypt	17.7	7.0	24.7	35.7	—	35.7	53.4	7.0	60.4
North Sea	0.6	1.0	1.6	4.2	0.6	4.8	4.8	1.6	6.4
Other International	—	1.5	1.5	—	—	—	—	1.5	1.5
Total	18.3	9.5	27.8	86.2	1.4	87.6	104.5	10.9	115.4
2019
United States	6.3	—	6.3	181.0	—	181.0	187.3	—	187.3
Egypt	8.5	13.5	22.0	37.2	1.5	38.7	45.7	15.0	60.7
North Sea	—	—	—	8.4	—	8.4	8.4	—	8.4
Total	14.8	13.5	28.3	226.6	1.5	228.1	241.4	15.0	256.4

5

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2021, is set forth below:

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	8,862	5,309	957	663	9,819	5,972
Egypt	1,026	991	114	111	1,140	1,102
North Sea	164	121	13	8	177	129
Total	10,052	6,421	1,084	782	11,136	7,203
Domestic	8,862	5,309	957	663	9,819	5,972
Foreign	1,190	1,112	127	119	1,317	1,231
Total	10,052	6,421	1,084	782	11,136	7,203

Gross natural gas and crude oil wells include 494 wells with multiple completions.

Production, Pricing, and Lease Operating Cost Data

The following table describes, for each of the last three fiscal years, oil, NGL, and gas production volumes, average lease operating costs per boe (including transportation costs but excluding severance and other taxes), and average sales prices for each of the countries where the Company has operations:

	Production			Average Lease Operating   Cost per Boe		Average Sales Price
	Oil	NGL	Gas			Oil		NGL		Gas
Year Ended December 31,	(MMbbls)	(MMbbls)	(Bcf)			(Per bbl)		(Per bbl)		(Per Mcf)
2021
United States	27.4	24.2	192.5	$	8.37	$	67.37	$	27.85	$	3.92
Egypt(1)	25.7	0.2	96.2	11.48		70.33		48.84		2.81
North Sea(2)	13.2	0.4	14.1	26.12		69.67		54.30		12.96
Total	66.3	24.8	302.8	11.31		68.97		28.48		3.99
2020
United States	32.3	27.1	205.6	$	7.39	$	37.42	$	11.21	$	1.22
Egypt(1)	27.6	0.3	100.4	10.35		39.95		27.83		2.79
North Sea(2)	18.4	0.7	21.0	15.60		42.88		29.73		3.19
Total	78.3	28.1	327.0	9.37		39.60		11.84		1.83
2019
United States	38.3	25.0	233.5	$	9.24	$	54.71	$	14.95	$	1.26
Egypt(1)	30.9	0.3	104.4	10.77		63.76		33.87		2.83
North Sea(2)	18.2	0.6	19.9	16.75		65.10		36.83		4.48
Total	87.4	25.9	357.8	10.62		60.05		15.74		1.90

(1)Includes production volumes attributable to a one-third noncontrolling interest in Egypt.

(2)Sales volumes from the Company’s North Sea assets for 2021, 2020, and 2019 were 16.1 MMboe, 22.7 MMboe, and 21.8 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

Gross and Net Undeveloped and Developed Acreage

The following table summarizes the Company’s gross and net acreage position as of December 31, 2021:

	Undeveloped Acreage		Developed Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres
	(In thousands)
United States	2,862	1,278	947	568
Egypt	3,610	3,610	1,690	1,634
North Sea	309	290	185	139
Total	6,781	5,178	2,822	2,341

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As of December 31, 2021, Apache held 246,000 net undeveloped acres that are scheduled to expire by year-end 2022 if production is not established or the Company takes no action to extend the terms. The Company also held 10,000 and 97,000 net undeveloped acres set to expire by year-end 2023 and 2024, respectively. The Company strives to extend the terms of many of these licenses and concession areas through operational or administrative actions but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments. No oil and gas reserves were recorded on this undeveloped acreage set to expire.

Exploration concessions in the Company’s Egypt asset were extended upon ratification of the modernized PSC with the EGPC, and no acreage is scheduled to expire over the next three years. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist.

As of December 31, 2021, approximately 93 percent of U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights.

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.

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The following table shows proved oil, NGL, and gas reserves as of December 31, 2021, based on average commodity prices in effect on the first day of each month in 2021, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. The total column of this table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.

	Oil	NGL	Gas	Total
	(MMbbls)	(MMbbls)	(Bcf)	(MMboe)
Proved Developed:
United States	181	164	1,238	551
Egypt(1)	107	1	465	185
North Sea	77	2	76	92
Total	365	167	1,779	828
Proved Undeveloped:
United States	18	16	184	65
Egypt(1)	11	—	10	13
North Sea	6	—	7	7
Total	35	16	201	85
Total Proved	400	183	1,980	913

(1)Includes total proved developed and total proved undeveloped reserves of 62 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.

As of December 31, 2021, Apache had total estimated proved reserves of 400 MMbbls of crude oil, 183 MMbbls of NGLs, and 2.0 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 913 million boe, of which liquids represents 64 percent. As of December 31, 2021, the Company’s proved developed reserves totaled 828 MMboe and estimated PUD reserves totaled 85 MMboe, or approximately 9 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing. The Company has one field that contains 15 percent or more of its total proved reserves for the years ended December 31, 2021 and 2020, and none in 2019.

During 2021, the Company added 102 MMboe of proved reserves through exploration and development activity. There were also upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operations. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to the Permian Basin.

As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.

The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2021, 2020, and 2019, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 19—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

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Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 85 MMboe as of December 31, 2021, increased by 9 MMboe from 76 MMboe of PUD reserves reported at year end 2020. During the year, Apache converted 33 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 28 MMboe, with the remaining 5 MMboe in its international areas. Apache sold 2 MMboe of PUD reserves in the U.S. and did not acquire any PUD reserves during the year. Apache added 63 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 19 MMboe, comprising 7 MMboe associated with engineering and interest revisions, 11 MMboe associated with revised development plans, and 1 MMboe associated with product prices.

During 2021, a total of approximately $213 million was spent on projects associated with proved undeveloped reserves. A portion of Apache’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2021, Apache spent approximately $174 million on PUD reserve development activity in the U.S. and $39 million in the international areas. As of December 31, 2021, Apache had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.

Preparation of Oil and Gas Reserve Information

Apache’s reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.

Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Reserves are reviewed internally with senior management and presented to Apache’s board of directors (the Board of Directors) in summary form on a quarterly basis. Annually, each property is reviewed in detail by our corporate and operating asset engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.

Apache’s Executive Vice President of Development is the person primarily responsible for overseeing the preparation of the Company’s internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 30 years of experience in the energy industry and energy sector of the banking industry. The Executive Vice President of Development reports directly to the Company’s Chief Executive Officer.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year and reserves volume. During 2021, the properties selected for each country ranged from 82 to 84 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 83 percent of the value of Apache’s international proved reserves and 94 percent of the value of Apache’s new wells drilled worldwide. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 80 percent of total proved reserves on a boe basis.

Ryder Scott’s review for the years 2021, 2020, and 2019 covered 83, 85, and 87 percent, respectively, of the value and 80, 81, and 85 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2021 review covered 80, 80, and 81 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.

Ryder Scott’s review of 2020 covered 80 percent of U.S., 82 percent of Egypt, and 83 percent of the U.K.’s total proved reserves.

Ryder Scott’s review of 2019 covered 85 percent of U.S., 86 percent of Egypt, and 80 percent of the U.K.’s total proved reserves.

The Company has filed Ryder Scott’s independent report as an exhibit to this Annual Report on Form 10-K.

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According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by Apache, the overall procedures and methodologies utilized by Apache in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by Apache are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.

ALTUS MIDSTREAM

In November 2018, Apache Midstream LLC, one of Apache’s wholly owned subsidiaries, completed a transaction with Altus Midstream Company (ALTM) and its then wholly owned subsidiary Altus Midstream LP to create a pure-play, Permian Basin midstream C-corporation anchored by gathering, processing, and transmission assets at Alpine High. Pursuant to the agreement, Apache’s subsidiary contributed certain Alpine High midstream assets and options (the Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, Apache’s subsidiary received economic voting and non-economic voting shares in ALTM and limited partner interests in Altus Midstream LP, representing an approximate 79 percent ownership interest in the combined entities.

Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.

Business Combination with BCP

On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement dated as of that same date and entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination creates an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. There are numerous expected commercial and financial synergies generated from the complementary midstream systems and enhanced scale of the business. The combined business will have a more diversified asset profile and customer base, with a lower risk profile than either entity on a stand-alone basis. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline. Pursuant to the BCP Contribution Agreement, Contributor will contribute all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination).

As consideration for the contribution of the Contributed Interests, ALTM will issue 50 million shares of Class C Common Stock (and Altus Midstream LP will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.

As a result of the transaction, ALTM’s current stockholders will continue to hold their shares of Class A Common Stock and Class C Common Stock (collectively, ALTM Common Stock), Contributor or its designees will collectively own approximately 75 percent of the issued and outstanding shares of ALTM Common Stock, Apache Midstream LLC, a wholly owned subsidiary of the Company, which currently owns approximately 79 percent of the issued and outstanding shares of ALTM Common Stock, will own approximately 20 percent of the issued and outstanding shares of ALTM Common Stock, and the remaining current stockholders will own approximately 5 percent of the issued and outstanding shares of ALTM Common Stock.

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Gathering, Processing, and Transmission Assets

Altus owns, develops, and operates gas gathering, processing, and transmission assets in the Permian Basin of West Texas. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services for Apache’s production from its Alpine High resource play. As of December 31, 2021, Altus’ assets included approximately 182 miles of in-service natural gas gathering pipelines, approximately 46 miles of residue-gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Altus’ existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and third-party customers as market activity in the area continues to develop.

Pipeline Options and Equity Method Interest Pipelines

Gulf Coast Express Pipeline In December 2018, Altus Midstream LP closed on the exercise of its Pipeline Option with Kinder Morgan Texas Pipeline LLC (Kinder Morgan), thereby acquiring a 15 percent equity interest in the Gulf Coast Express Pipeline Project (GCX). Altus Midstream LP acquired an additional 1 percent equity interest in May 2019, for a total 16 percent equity interest in GCX. GCX is a long-haul natural gas pipeline with capacity of approximately 2.0 Bcf/d and transports natural gas from the Waha area in Northern Pecos County, Texas to the Agua Dulce Hub near the Texas Gulf Coast. GCX is operated by Kinder Morgan and was placed into service in September 2019.

EPIC Crude Oil Pipeline In March 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with EPIC Pipeline LP, thereby acquiring a 15 percent equity interest in the EPIC crude oil pipeline (EPIC). The long-haul crude oil pipeline extends from the Orla area in Northern Reeves County, Texas to the Port of Corpus Christi, Texas, and has Permian Basin initial throughput capacity of approximately 600 MBbl/d. The project includes terminals in Orla, Pecos, Crane, Wink, Robstown, Hubson, and Gardendale, Texas with Port of Corpus Christi connectivity and export access. It services Delaware Basin, Midland Basin, and Eagle Ford Shale production. EPIC is operated by EPIC Consolidated Operations, LLC and was placed into service in early 2020.

Permian Highway Pipeline In May 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Kinder Morgan, thereby acquiring an approximate 26.7 percent equity interest in the Permian Highway Pipeline (PHP). The long-haul natural gas pipeline has capacity of approximately 2.1 Bcf/d and transports natural gas from the Waha area in Northern Pecos County, Texas to the Katy, Texas area with connections to U.S. Gulf Coast and Mexico markets. PHP, which is operated by Kinder Morgan, was placed into service in January 2021.

Shin Oak NGL Pipeline In July 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Enterprise Products Operating LLC (Enterprise Products), thereby acquiring a 33 percent equity interest in Breviloba LLC, which owns the Shin Oak NGL Pipeline (Shin Oak). The long-haul NGL pipeline has capacity of up to 550 MBbl/d and transports NGL production from the Orla area in Northern Reeves County, Texas through the Waha area in Northern Pecos County, Texas, and on to Mont Belvieu, Texas. Shin Oak is operated by Enterprise Products and was placed into service during 2019.

MAJOR CUSTOMERS

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.

Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.

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OFFICES

The Company’s principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. As of year-end 2021, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache leases its primary office space. The current lease on the Company’s principal executive offices runs through December 31, 2024. The Company has an option to extend the lease through 2029. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

TITLE TO INTERESTS

As is customary in the oil and gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time the Company acquires properties. The Company believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Company’s operations. The interests owned by the Company may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.

ADDITIONAL INFORMATION ABOUT THE COMPANY

Response Plans and Available Resources

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective offshore operations in the Gulf of Mexico and the North Sea, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Annually, drills are conducted to measure and maintain the effectiveness of the Plans.

Apache is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any affiliated entity worldwide to access OSRL’s services. Apache also has a contract for response resources and services with National Response Corporation (NRC). NRC is the world’s largest commercial Oil Spill Response Organization and is the global leader in providing end-to-end environmental, industrial, and emergency response solutions with operating bases in 13 countries.

In the event of a spill in the Gulf of Mexico, Clean Gulf Associates (CGA) is the primary oil spill response association available to Apache and ADW. Both Apache and ADW are members of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico.

Competitive Conditions

The oil and gas industry is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and the gathering and marketing of oil, gas, and NGLs. The Company’s competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.

Certain of the Company’s competitors may possess financial or other resources substantially larger than the Company possesses or have established strategic long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for leases or drilling rights.

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However, the Company believes its diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across three geographic areas, its balanced production mix between oil and gas, its management and incentive systems, and its experienced personnel give it a strong competitive position relative to many of the Company’s competitors who do not possess similar geographic and production diversity. The Company’s global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which it has producing operations to which it can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. This also reduces the risk that the Company will be materially impacted by an event in a specific area or country.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties and facilities, the Company is subject to numerous federal, state, local, and foreign laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry as a whole, the Company does not believe that these requirements affect it differently, to any material degree, than other companies in the oil and gas industry.

The Company has made and will continue to make expenditures in its efforts to comply with these requirements, which the Company believes are necessary business costs in the oil and gas industry. The Company has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to its operations in all countries in which it does business. The Company has established operating procedures and training programs designed to limit the environmental impact of its field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that the Company is unable to separate expenses related to environmental matters; however, the Company does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures, earnings, or competitive position.

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ITEM 1A. RISK FACTORS

The Company’s business activities and the value of its securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA’s securities could lose part or all of their investments. Additional risks relating to the Company’s securities may be included in the prospectus supplements related to offerings of such securities from time to time in the future.

RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NGLs

The COVID-19 pandemic has and may continue to adversely impact the Company’s business, financial condition, and results of operations, the global economy, and the demand for and prices of oil, natural gas, and NGLs. The unprecedented nature of the current situation makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business.

The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic have adversely impacted the global economy and created significant volatility in the global financial markets. Business closures, restrictions on travel, “stay-at-home” or “shelter-in-place” orders, and other restrictions on movement within and among communities have significantly reduced demand for and the prices of oil, natural gas, and NGLs. As of the date of this Annual Report on Form 10-K, efforts to contain COVID-19 have not been successful in many regions, vaccination distribution programs have encountered delays, new variants have emerged, and the global pandemic remains ongoing. While some geographic regions have lifted, relaxed, or otherwise modified their pandemic response measures to lessen the impact of such measures on business operations and commerce, these regions may reinstitute restrictions as circumstances change. A continued, prolonged period or a renewed period of reduced demand, the failure to timely distribute or the ineffectiveness of or reluctance or refusal of individuals to take any vaccines, the failure to develop adequate treatments, and other adverse impacts from the pandemic may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations.

The Company’s operations rely on its workforce being able to access its wells, platforms, structures, and facilities located upon or used in connection with its oil and gas leases. Additionally, because the Company has previously implemented, and may elect to or be required in the future to reimplement, remote working procedures for a significant portion of its workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, the Company relies on such persons having sufficient access to its information technology systems, including through telecommunication hardware, software, and networks. If a significant portion of the Company’s workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, including vaccine mandates and the reactions thereto, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.

The unprecedented nature of the current situation resulting from the COVID-19 pandemic makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business, financial condition, cash flows, or results of operations. Such results will depend on future events, which the Company cannot predict, including the scope, duration, and potential reoccurrence of the COVID-19 pandemic, the emergence and impact of COVID-19 variants, or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines, therapeutics, and treatments, the demand for and the prices of oil, natural gas, and NGLs, and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have amplified, and may continue to amplify, the other risks identified in this Annual Report on Form 10-K.

Crude oil, natural gas, and NGL price volatility could adversely affect the Company’s operating results.

The Company’s revenues, operating results, and future rate of growth depend highly upon the prices it receives for its crude oil, natural gas, and NGL production. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2021 ranged from a high of $85.64 per barrel to a low of $47.47 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2021 ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company’s control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:

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•worldwide and domestic supplies of crude oil, natural gas, and NGLs;

•actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);

•political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;

•the occurrence of global events such as epidemics or pandemics (including, specifically, the COVID-19 pandemic) 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 level of global crude oil and natural gas inventories;

•the price and level of imported foreign crude oil, natural gas, and NGLs;

•the price and availability of alternative fuels, including coal and biofuels;

•the availability of pipeline capacity and infrastructure;

•the availability of crude oil transportation and refining capacity;

•weather conditions;

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

•domestic and foreign governmental regulations and taxes, including legislative, regulatory, policy changes, or initiatives and addressing the impact of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and

•the overall economic environment.

The Company’s results of operations, as well as the carrying value of its oil and gas properties, are substantially dependent upon the prices of oil, natural gas, and NGLs. Low prices have previously adversely affected and could again adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and continued low prices could have a material adverse impact on the Company’s operations and limit its ability to fund capital expenditures. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs may further adversely impact the Company’s business as follows:

•weakening the Company’s financial condition and reducing its liquidity;

•limiting the Company’s ability to fund planned capital expenditures and operations;

•reducing the amount of crude oil, natural gas, and NGLs that the Company can produce economically;

•causing the Company to delay or postpone some of its capital projects;

•reducing the Company’s revenues, operating income, and cash flows;

•limiting the Company’s access to sources of capital, such as equity and long-term debt;

•reducing the carrying value of the Company’s oil and gas properties, resulting in additional non-cash impairments; or

•reducing the carrying value of the Company’s gathering, processing, and transmission facilities, resulting in additional impairments.

The Company’s ability to sell crude oil, natural gas, or NGLs and/or receive market prices for these commodities and/or meet volume commitments under transportation services agreements may be adversely affected by pipeline and gathering system capacity constraints, the inability to procure and resell volumes economically, and various transportation interruptions.

A portion of the Company’s crude oil, natural gas, and NGL production in any region may be interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities, or interstate pipelines to transport the Company’s production, or the Company might voluntarily curtail production in response to market conditions. If a substantial amount of the Company’s production is interrupted at the same time, it could temporarily adversely affect the Company’s cash flows. Additionally, if the Company is unable to procure

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and resell third-party volumes at or above a net price that covers the cost of transportation, the Company’s cash flows could be adversely affected.

The Company may not realize an adequate return on wells that it drills.

Drilling for oil and gas involves numerous risks, including the risk that the Company will not encounter commercially productive oil or gas reservoirs. The wells the Company drills or participates in may not be productive, and the Company may not recover all or any portion of its investment in those wells. The seismic data and other technologies the Company uses do not allow it to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:

•unexpected drilling conditions;

•pressure or irregularities in formations;

•equipment failures or accidents;

•fires, explosions, blowouts, and surface cratering;

•marine risks, such as capsizing, collisions, and hurricanes;

•other adverse weather conditions; and

•increases in the cost of or shortages or delays in the availability of drilling rigs and equipment.

Future drilling activities may not be successful, and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

The Company’s commodity price risk management and trading activities may prevent it from benefiting fully from price increases and may expose it to other risks.

To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Company’s hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

•the Company’s production falls short of the hedged volumes;

•there is a widening of price-basis differentials between delivery points for the Company’s production and the delivery point assumed in the hedge arrangement;

•the counterparties to the Company’s hedging or other price risk management contracts fail to perform under those arrangements; or

•an unexpected event materially impacts commodity prices.

RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS

The Company’s operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of equipment, and environmental accidents.

The Company’s operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including:

•well blowouts, explosions, fires, and cratering;

•pipeline or other facility ruptures and spills;

•formations with abnormal pressures;

•equipment malfunctions;

•hurricanes, major storms, and cyclones, which could affect the Company’s operations in areas such as on and offshore the Gulf Coast, North Sea, and Suriname, and other natural and anthropogenic disasters and weather conditions; and

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•surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.

Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters, such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where the Company’s equipment and services are used, or ground water contamination from chemical additives used in hydraulic fracturing may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of the Company’s production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company’s cash flows and, in turn, its results of operations could be materially and adversely affected.

Weather and climate may have a significant adverse impact on the Company’s revenues and production.

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price the Company receives for the commodities it produces. In addition, the Company’s exploration, development, and production activities and equipment have been and can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico, or major storms in the North Sea, which have previously caused and may cause a loss of production from temporary cessation of activity or lost or damaged equipment. The Company’s planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against.

The Company’s insurance policies do not cover all of the risks the Company faces, which could result in significant financial exposure.

Exploration for and production of crude oil, natural gas, and NGLs can be hazardous, involving natural disasters and other events such as blowouts, cratering, fires, explosions, and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company’s international operations are also subject to political risk. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks.

A terrorist or cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company’s operations.

The Company’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. The Company depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with personnel and third-party partners, and conduct many of the Company’s activities. Unauthorized access to the Company’s digital technology could lead to operational disruption, data corruption, communication interruption, loss of intellectual property, loss of confidential and fiduciary data, and loss or corruption of reserves or other proprietary information. Also, external digital technologies control nearly all of the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company’s production. A cyberattack directed at oil and gas distribution systems have previously and could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. Any such terrorist attack, environmental activist group activity, or cyberattack that affects the Company or its customers, suppliers, or others with whom it does business could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.

While certain of the Company’s insurance policies may allow for coverage of associated damages resulting from such events, if the Company were to incur a significant liability for which it was not fully insured, that could have a material adverse effect on the Company’s financial position, results of operations, and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

While the Company has experienced cyberattacks in the past, it has not suffered any material losses as a result of such attacks; however, there is no assurance that the Company will not suffer such losses in the future. Further, as cyberattacks continue to evolve, the Company may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against the

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Company or others in its industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures. The Company cannot predict the potential impact that such additional regulations could have on its business and operations or the energy industry at large.

Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects.

The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect the Company’s large development projects and its ability to participate in large-scale development projects in the future. In addition, the Company’s estimates of future development costs are based on its current expectations of prices and other costs of equipment and personnel the Company will need to implement such projects. The actual future development costs may be significantly higher than the Company currently estimates. If costs become too high, the development projects may become uneconomic to the Company, and it may be forced to abandon such development projects.

RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE

Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.

The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless the Company adds reserves through exploration and development activities, identifies additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquires additional properties containing proved reserves, the Company’s estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon the Company’s level of success in acquiring or finding additional reserves on an economic basis. Furthermore, as oil or natural gas prices increase, the Company’s cost for additional reserves could also increase.

The Company may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.

Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, the Company will focus its review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit the Company as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company often assumes certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon the Company’s operating results, particularly during the periods in which the operations of acquired businesses are being integrated into the Company’s ongoing operations.

Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.

There are numerous uncertainties inherent in estimating crude oil, natural gas, and NGL reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas, and NGLs that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise and a function of the quality of available data and the engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:

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•historical production from the area compared with production from other areas;

•the effects of regulations by governmental agencies, including changes to severance and excise taxes;

•future operating costs and capital expenditures; and

•workover and remediation costs.

For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties, classifications of those reserves, and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates.

Additionally, because some of the Company’s reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

Certain of the Company’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A sizeable portion of the Company’s acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company’s drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

RISKS RELATED TO COUNTERPARTIES

The credit risk of financial institutions could adversely affect the Company.

The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions. These transactions expose the Company to credit risk in the event of default of the counterparty. Deterioration in the credit or financial markets may impact the credit ratings of the Company’s current and potential counterparties and affect their ability to fulfill their existing obligations to the Company and their willingness to enter into future transactions with the Company. The Company may also have exposure to financial institutions in the form of derivative transactions in connection with any hedges. The Company also has exposure to insurance companies in the form of claims under the Company’s policies. In addition, if any lender under the Company’s credit facilities is unable to fund its commitment, the Company’s liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit facilities.

The Company is exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the recent volatility of the financial markets and significant changes in commodity prices, which could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Company is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Company does accurately predict sudden changes, its ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Company’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities. During periods of falling commodity prices, the Company’s hedge receivable positions increase, which increases the Company’s exposure. If the creditworthiness of the counterparties deteriorates and results in their nonperformance, the Company could incur a significant loss.

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The distressed financial conditions of the Company’s purchasers and partners have had and could have an adverse impact on the Company in the event they are unable to pay the Company for the products or services it provides or to reimburse it for their share of costs.

Concerns about global economic conditions and the volatility of oil, natural gas, and NGL prices have had a significant adverse impact on the oil and gas industry. The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. The Company sells its crude oil, natural gas, and NGLs to a variety of purchasers. As operator, the Company pays expenses and bills its non-operating partners for their respective shares of costs. As a result of recent economic conditions and the previously severe decline in commodity prices, some of the Company’s customers and non-operating partners experienced severe financial problems that had a significant impact on their creditworthiness. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company or that such a default or defaults will not have a material adverse effect on the Company’s business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of the Company’s customers or non-operating partners or some other similar proceeding or liquidity constraint have made it and might make it unlikely that the Company will or would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.

The Company’s liabilities could be adversely affected in the event one or more of its transaction counterparties become the subject of a bankruptcy case.

From time to time the Company has divested noncore or nonstrategic domestic and international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, bonds, letters of credit, and similar arrangements. One of the most significant of these liabilities involves the decommissioning of wells and facilities previously owned by the Company. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress. In the event that any such counterparty becomes the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which are collectively referred to as Insolvency Laws), the counterparty may not perform its obligations under the agreements related to these transactions. In that case, the Company’s remedy in the proceeding would be a claim for damages for the breach of the contractual arrangements, which may be either a secured claim or an unsecured claim depending on whether or not the Company has collateral from the counterparty for the performance of the obligations. Resolution of the Company’s claim for damages in such a proceeding may be delayed, and the Company may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise, pending final resolution of the proceeding.

Despite the provisions in the Company’s agreements requiring purchasers of its state or federal leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws or becomes unable financially to perform such liabilities or obligations, the Company would expect the relevant governmental authorities to require it to perform and hold it responsible for such liabilities and obligations. In such event, the Company may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, it could adversely impact the Company’s cash flows, operations, or financial condition.

For additional information regarding Apache’s prior Gulf of Mexico properties and the bankruptcy of the purchaser of those properties, see the information set forth under “Potential Obligation to Decommission Sold Properties” in Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Item 15 of this Annual Report on Form 10-K.

The Company does not always control decisions made under joint operating agreements, and the parties under such agreements may fail to meet their obligations.

The Company conducts many of its exploration and production (E&P) operations through joint operating agreements with other parties under which the Company may not control decisions, either because it does not have a controlling interest or is not an operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with the Company’s, and therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations,

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and the Company may be required to fulfill those obligations alone. In either case, the value of the investment may be adversely affected.

The Company own an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus may be subject to different risks than those described in this Annual Report on Form 10-K.

The Company owns an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to service the Company’s production from Apache’s Alpine High resource play. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services and through its Equity Method Interest Pipelines. Given the nature of its business, Altus may be subject to different and additional risks than those described in this Annual Report on Form 10-K. For a description of these risks, refer to Altus’ most recently filed Annual Report on Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q.

On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions. Upon closing of the transaction, the Company will no longer control Altus.

RISKS RELATED TO CAPITAL MARKETS

A downgrade in the Company’s credit rating could negatively impact its cost of and ability to access capital.

The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company’s credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company’s ability to access debt markets in the future and increase the cost of future debt. During 2021, the Company’s credit rating was affirmed by Moody’s to Ba1/Stable and by Standard and Poor’s to BB+/Stable. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.

Market conditions may restrict the Company’s ability to obtain funds for future development and working capital needs, which may limit its financial flexibility.

The financial markets are subject to fluctuation and are vulnerable to unpredictable shocks. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company’s future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of the Company’s property interests.

The Company’s syndicated credit facility currently matures in March 2024. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to the Company or its subsidiaries or the composition of such lenders.

The discontinuation and uncertain cessation date of LIBOR, and the adoption of an alternative reference rate, may have a material adverse impact on the Company’s floating rate indebtedness and financing costs.

Pursuant to the terms of the Company’s revolving credit facility (1) the Company may elect to use the London Interbank Offering Rate (LIBOR) as a benchmark for establishing the interest rate on floating interest rate borrowings and (2) the commission payable to the lenders on the face amount of each outstanding letter of credit uses LIBOR as a benchmark. On November 30, 2020, the ICE Benchmark Administration (IBA) announced that it intends to continue publishing LIBOR until the end of June 2023, beyond the previously announced 2021 cessation date. The IBA announcement was supported by announcements from the U.K.’s Financial Conduct Authority (FCA), which regulates LIBOR, and the Board of Governors of the Federal Reserve System, Federal Deposit Insurance Corporation and Office of the Comptroller of the Currency (U.S. Regulators). However, both the FCA and U.S. Regulators in their announcements also advised banks to cease entering into new contracts referencing LIBOR after December 2021. These announcements indicate that the continuation of LIBOR in existing contracts may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future

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of LIBOR at this time is uncertain, and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist.

In the U.S., the Alternative Reference Rates Committee (the working group formed to recommend an alternative rate to LIBOR) has identified the Secured Overnight Financing Rate (SOFR) as its preferred alternative rate for LIBOR. There can be no guarantee that SOFR will become a widely-accepted benchmark in place of LIBOR. Although the full impact of the transition away from LIBOR, including the discontinuance of LIBOR publication and the adoption of SOFR as the replacement rate for LIBOR, remains unclear, these changes may have an adverse impact on the Company’s floating rate indebtedness and financing costs under its revolving credit facility.

Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry.

Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. In addition, certain organizations and stakeholders may encourage lenders to limit funding to E&P companies. Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry, which could have a negative impact on the Company’s access to and costs of capital.

RISKS RELATED TO FINANCIAL RESULTS

Future economic conditions in the U.S. and certain international markets may materially adversely impact the Company’s operating results.

Current global market conditions and uncertainty, including economic instability in emerging markets, are likely to have significant long-term effects on the Company’s operating results. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for the Company’s oil and natural gas production as well as lower commodity prices, which would reduce the Company’s cash flows from operations and its profitability.

The Company faces strong industry competition that may have a significant negative impact on the Company’s results of operations.

Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes with major integrated and other independent oil and gas companies for acquisitions of oil and gas leases, properties, and reserves, equipment and labor required to explore, develop, and operate those properties, and marketing of crude oil, natural gas, and NGL production. Crude oil, natural gas, and NGL prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of the Company’s competitors have financial and other resources substantially larger than the Company possesses and have established strategic, long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for drilling rights. In addition, many of the Company’s larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. The Company also competes in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on the Company’s results of operations.

The Company’s ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.

As described in Note 11—Income Taxes of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company’s equity ownership by five-percent shareholders over a three-year period, the Company’s ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company’s operating results or cash flows by effectively increasing its future tax obligations.

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RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS

The Company may incur significant costs related to environmental matters.

As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. The Company’s efforts to limit its exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company’s results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require the Company to make significant capital expenditures. Such capital expenditures could adversely impact the Company’s cash flows and its financial condition.

The Company’s U.S. operations are subject to governmental risks.

The Company’s U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations.

In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010 and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) issued guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico.

With respect to oil and gas operations in the Gulf of Mexico, the BOEM issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.

New political developments, the enactment of new or stricter laws or regulations or other governmental actions impacting the Company’s U.S. operations, and increased liability for companies operating in this sector may adversely impact the Company’s results of operations.

Proposed federal, state, or local regulation regarding hydraulic fracturing could increase the Company’s operating and capital costs.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states and political subdivisions are considering legislation, ballot initiatives, executive orders, or other actions to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to induced seismicity. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing or are considering doing so. The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in formations with low permeability.

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Although it is not possible at this time to predict the final outcome of the governmental actions regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which the Company conducts business could result in increased compliance costs or additional operating restrictions in the U.S.

Changes in tax rules and regulations, or interpretations thereof, may adversely affect the Company’s business, financial condition, and results of operations.

The U.S. federal and state income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. Previous legislative proposals, if enacted into law, could make significant changes to such laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas E&P companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development. The Company is unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect the Company’s business, financial condition, and results of operations.

RISKS RELATED TO CLIMATE CHANGE

Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact the Company’s business.

Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company’s operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company’s cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding legislation or regulation of GHG. Numerous proposals have been made and could continue to be made at the national, regional, and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. Moreover, on January 27, 2021, the President issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas, and NGLs. Additionally, political, litigation, and financial risks related to climate change may result in curtailed refinery activity, increased regulation, or other adverse direct and indirect effects on the Company’s business, financial condition, and results of operations. For example, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company’s operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications.

Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.

Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.

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The Company’s estimates used in various scenario planning analyses could differ materially from actual results and could expose us to new or additional risks.

In 2021, the Company undertook a scenario planning analysis in alignment with recommendations of the Financial Stability Board’s Taskforce on Climate-related Financial Disclosures (“TCFD”). This expanded climate-focused scenario planning framework included forecasts of future demand and pricing in energy markets, as well as changes in government regulations and policy. Given the dynamic nature of the Company’s business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term TCFD scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company’s internally prepared base-case pricing analysis averaged out to 2040. Given the numerous estimates that are required to run these scenarios, the Company’s estimates could differ materially from actual results. Additionally, by electing to set and share publicly these metrics in the Company’s sustainability report and the Company’s commitment to expand upon its disclosures, the Company’s business may also face increased scrutiny related to ESG initiatives. As a result, the Company could damage its reputation if it fails to act responsibly in the areas in which it reports. Any harm to the Company’s reputation resulting from setting these metrics, expanding its disclosures, or its failure or perceived failure to meet such metrics or disclosures could adversely affect the Company’s business, financial performance, and growth.

The Company operates in Gulf Coast wetlands, which face threats from climate change and human activities.

A changing climate creates uncertainty and could result in broad changes, both physical and financial, to the areas in which the Company operates, including Gulf Coast wetlands. For several decades, the State of Louisiana has lost an estimated 20 square miles of wetlands per year, due to natural processes of subsidence, saltwater intrusion, and shoreline erosion, as well as human activities, such as levee construction along the Mississippi River and the dredging of navigation canals. A possible result of climate change is more frequent and more severe weather events, such as hurricanes and major flooding events. The risk of increased or more severe hurricanes or flooding events along or near the Gulf Coast could increase the Company’s costs to repair damaged facilities and restore production. Additionally, federal, state, and local laws and regulations may impose numerous obligations applicable to the Company’s operations including: (i) the limitation or prohibition of certain activities on wetlands; (ii) the imposition of substantial liabilities for pollution resulting from operations; (iii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with protected properties; and (iv) the installation of costly emission monitoring and/or pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of the Company’s operations. In addition, the Company may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt the Company’s operations or specific projects and limit its growth and revenue.

The guidance upon which the Company’s consumptive water use reporting was modified and could be revised in the future, resulting in the over or underreporting of the Company’s consumptive water use, and could expose the Company to financial risk.

Based on Ipieca’s Sustainability Reporting Guidance of the Oil and Gas Industry (2020), the Company modified the way it reports its water data compared to previous years and also restated data from past years. Previously, the Company included produced water usage in its consumptive use calculations, which led to an over-reporting of consumptive water use. Based on re-evaluation of water reporting definitions and guidance, the Company determined that produced water – non-potable water released from deep underground formations and brought to the surface during oil and gas exploration and production – should not be classified as consumed in the same sense as fresh water. Produced water is generally not of the quality that most users would be able to utilize and is therefore not available for third-party usage outside of the oilfield. The Company’s revised reporting now reflects only fresh water and non-potable water from surface water or shallow groundwater that are consumed in oil and gas operations.

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

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

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particularly such activity related to injection wells used for produced water disposal. In September 2021, the RRC began to limit saltwater disposal in the Midland Basin under what is known as a Seismic Response Action (or SAR) due to increased seismic activity. These developments could result in restriction of disposal wells that could have a material effect on the Company’s capital expenses and operating costs or limit production in certain areas.

RISKS RELATED TO INTERNATIONAL OPERATIONS

International operations have uncertain political, economic, and other risks.

The Company’s operations outside the U.S. are based primarily in Egypt and the U.K. On a barrel equivalent basis, approximately 41 percent of the Company’s 2021 production was outside the U.S., and approximately 32 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2021, were located outside the U.S. As a result, a significant portion of the Company’s production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:

•general strikes and civil unrest;

•the risk of war, acts of terrorism, expropriation and resource nationalization, and forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts;

•import and export regulations;

•taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;

•price control;

•transportation regulations and tariffs;

•constrained oil or natural gas markets dependent on demand in a single or limited geographical area;

•exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds;

•laws and policies of the U.S. affecting foreign trade, including trade sanctions;

•the long-term effects of the U.K.’s withdrawal from the European Union, including any resulting instability in global financial markets or the value of foreign currencies such as the British pound;

•the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates;

•the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and

•difficulties in enforcing the Company’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company’s interests could decrease in value or be lost. Even the Company’s smaller international assets may affect its overall business and results of operations by distracting management’s attention from its more significant assets. Certain regions of the world in which the Company operates have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as the Company’s. In an extreme case, such a change could result in termination of contract rights and expropriation of the Company’s assets. This could adversely affect the Company’s interests and its future profitability.

The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which the Company operates, may have on the oil and gas industry in general and on the Company’s operations in particular is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets or indirect casualties of an act of terror or war. The Company may be required to incur significant costs in the future to safeguard its assets against terrorist activities.

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A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on the Company’s business.

Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company’s assets or resource nationalization, and/or forced renegotiation or modification of the Company’s existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company’s business, financial condition, and results of operations. The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of the Company’s 2021 production and accounted for 16 percent of the Company’s year-end estimated proved reserves and 20 percent of the Company’s estimated discounted future net cash flows.

The Company’s operations are sensitive to currency rate fluctuations.

The Company’s operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. The Company’s financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect the Company’s results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 3. LEGAL PROCEEDINGS

The information set forth under “Legal Matters” and “Environmental Matters” in Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Apache is a wholly owned subsidiary of APA. Accordingly, all of Apache’s common stock, par value $0.625 per share, is owned by APA, and there is no market for Apache’s common stock.

ITEM 6. SELECTED FINANCIAL DATA

Omitted.

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ITEM 7. MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following discussion relates to Apache Corporation (Apache or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 (filed with the SEC on February 25, 2021).

On January 4, 2021, the Company announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, the Company became a direct, wholly owned subsidiary of APA Corporation (APA), and all of the Company’s outstanding shares were automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’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. Refer to Note 2—Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for more detail.

Overview

Apache, a direct, wholly owned subsidiary of APA, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). Apache’s midstream business (Altus Midstream) 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.

Apache believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. Today, the world faces a dual challenge: To meet growing demand for energy and to do so in a cleaner, more sustainable way. Apache believes society can accomplish both and strives to meet those challenges while creating value for all its stakeholders.

The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainties in the commodity and financial markets since early 2020 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its stakeholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

During 2021, the Company reported net income of $1.1 billion compared to a net loss of $4.9 billion in 2020. Net income in 2021 benefited from significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic negatively affected economic activity and the oil markets. In 2020, the Company recorded impairments totaling $4.5 billion in connection with fair value assessments stemming from the global crude oil price collapse.

The Company generated $3.5 billion of cash from operating activities in 2021, which was $2.1 billion, or 153 percent, higher than the prior year. Apache’s higher operating cash flows for 2021 were driven by higher crude oil and natural gas prices and associated revenues. The Company ended the year with a cash balance of $279 million, up $17 million from year-end 2020 after paying back nearly $1.4 billion of debt during 2021 in an effort to reduce near-term debt maturities and strengthening its balance sheet.

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Operational Highlights

Key operational highlights for the year include:

United States

•Daily boe production from the Company’s U.S. assets, which decreased 10 percent from the prior year end, accounted for 59 percent of its total worldwide production during 2021. After halting all drilling and completion activity for most of 2020, in response to completion cost reductions, the Company reinstated two operated completion crews in the Permian Basin in late 2020 to begin completing its backlog of drilled but uncompleted well inventory. In early 2021, the Company re-activated one drilling 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. For 2022, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves.

•On October 11, 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals three months ahead of schedule. The Company also seeks continuous improvement on its safety performance and protocols, having established key safety indicators and metrics that are rigorously managed and that impact annual incentive compensation Company-wide.

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

International

•In December 2021, the Egyptian President signed and ratified the previously announced agreement with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the Company’s production-sharing contracts (PSCs), having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool that provides improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The changes also simplify the contractual relationship with EGPC, facilitate recovery of prior investment, and update day-to-day operational governance. The Apache entity that is the sole contractor is owned two-thirds by Apache and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).

•Egypt gross equivalent production decreased 14 percent and net production decreased 6 percent from 2020, primarily a result of natural decline given reduced drilling activity in the past year. The modernized production sharing agreement did not impact 2021 production since it was ratified at the end of the year. The Company continues to build and enhance its robust drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage. The Company anticipates increased drilling and workover activity in 2022 as a result of the ratification of the new modernized PSC.

•The North Sea maintained two drilling rigs during 2021. During the year, production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages.

For a more detailed discussion related to the Company’s various geographic segments, refer to “Upstream Exploration and Production Properties—Operating Areas” set forth in Part I, Item 1 and 2 of this Annual Report on Form 10-K.

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Acquisition and Divestiture Activity

Over the Company’s history, it has repeatedly demonstrated the ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize Apache’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of divestitures designed to monetize nonstrategic assets and enhance the Company’s portfolio in order to allocate resources to more impactful exploration and development opportunities. These divestitures include:

•Permian Basin Divestiture In the second quarter of 2021, the Company completed the sale of certain non-core assets in the Central Basin Platform of the Permian Basin for total cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million.

•U.S. Leasehold Divestitures & Acquisitions During 2021, the Company completed the sale of other non-core assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. Also during 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.

•U.S. Leasehold Divestitures & Other During 2020, the Company completed the sale of certain non-core producing assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million. The Company also completed certain leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million.

For detailed information regarding Apache’s acquisitions and divestitures, refer to Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

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Results of Operations

Oil and Gas Production Revenues

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

	For the Year Ended December 31,
	2021				2020				2019
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	1,850	40	%	$	1,209	39	%	$	2,098	40	%
Egypt(1)	1,806		40	%	1,102		35	%	1,969		38	%
North Sea	929		20	%	795		26	%	1,163		22	%
Total(1)	$	4,585	100	%	$	3,106	100	%	$	5,230	100	%
Natural Gas Revenues:
United States	$	754	62	%	$	251	42	%	$	293	43	%
Egypt(1)	270		23	%	280		47	%	295		44	%
North Sea	183		15	%	67		11	%	90		13	%
Total(1)	$	1,207	100	%	$	598	100	%	$	678	100	%
NGL Revenues:
United States	$	673	95	%	$	304	91	%	$	372	91	%
Egypt(1)	9		1	%	8		3	%	12		3	%
North Sea	24		4	%	21		6	%	23		6	%
Total(1)	$	706	100	%	$	333	100	%	$	407	100	%
Oil and Gas Revenues:
United States	$	3,277	50	%	$	1,764	44	%	$	2,763	44	%
Egypt(1)	2,085		32	%	1,390		34	%	2,276		36	%
North Sea	1,136		18	%	883		22	%	1,276		20	%
Total(1)	$	6,498	100	%	$	4,037	100	%	$	6,315	100	%

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

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Production

The following table presents production volumes by country:

	For the Year Ended December 31,
	2021	Increase (Decrease)	2020	Increase (Decrease)	2019
Oil Volumes – b/d:
United States(5)	75,205	(15)%	88,249	(16)%	105,051
Egypt(3)(4)	70,349	(7)%	75,384	(11)%	84,617
North Sea	36,265	(28)%	50,386	1%	49,746
Total	181,819	(15)%	214,019	(11)%	239,414
Natural Gas Volumes – Mcf/d:
United States(5)	527,461	(6)%	561,731	(12)%	639,580
Egypt(3)(4)	263,653	(4)%	274,175	(4)%	285,972
North Sea	38,565	(33)%	57,464	5%	54,642
Total	829,679	(7)%	893,370	(9)%	980,194
NGL Volumes – b/d:
United States(5)	66,232	(11)%	74,136	8%	68,381
Egypt(3)(4)	531	(30)%	754	(19)%	931
North Sea	1,199	(38)%	1,936	11%	1,739
Total	67,962	(12)%	76,826	8%	71,051
BOE per day:(1)
United States(5)	229,348	(10)%	256,007	(9)%	280,029
Egypt(3)(4)	114,821	(6)%	121,834	(9)%	133,209
North Sea(2)	43,892	(29)%	61,899	2%	60,592
Total	388,061	(12)%	439,740	(7)%	473,830

(1)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.

(2)Average sales volumes from the North Sea were 44,179 boe/d, 62,157 boe/d, and 59,797 boe/d for 2021, 2020, and 2019, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

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

	2021	2020	2019
Oil (b/d)	134,711	164,104	193,886
Natural Gas (Mcf/d)	586,663	641,069	708,682
NGL (b/d)	854	1,429	1,722

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

	2021	2020	2019
Oil (b/d)	23,504	25,206	28,220
Natural Gas (Mcf/d)	88,409	91,540	95,539
NGL (b/d)	177	251	310

(5)Production volumes per day in the Company’s Alpine High field were as follows:

	2021	2020	2019
Oil (b/d)	1,485	2,718	3,475
Natural Gas (Mcf/d)	258,096	274,279	316,169
NGL (b/d)	22,950	24,942	17,446

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Pricing

The following table presents pricing information by country:

	For the Year Ended December 31,
	2021		Increase (Decrease)	2020		Increase (Decrease)	2019
Average Oil Price - Per barrel:
United States	$	67.37	80%	$	37.42	(32)%	$	54.71
Egypt	70.33		76%	39.95		(37)%	63.76
North Sea	69.67		62%	42.88		(34)%	65.10
Total	68.97		74%	39.60		(34)%	60.05
Average Natural Gas Price - Per Mcf:
United States	$	3.92	221%	$	1.22	(3)%	$	1.26
Egypt	2.81		1%	2.79		(1)	2.83
North Sea	12.96		306%	3.19		(29)%	4.48
Total	3.99		118%	1.83		(4)%	1.90
Average NGL Price - Per barrel:
United States	$	27.85	148%	$	11.21	(25)%	$	14.95
Egypt	48.84		75%	27.83		(18)%	33.87
North Sea	54.30		83%	29.73		(19)%	36.83
Total	28.48		141%	11.84		(25)%	15.74

Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2021 were up 74 percent compared to 2020, a direct result of the rising benchmark oil prices over the past year. Crude oil prices realized in 2021 averaged $68.97 per barrel.

Continued volatility in the commodity price environment reinforces the importance of the Company’s asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Price movements for all types and grades of crude oil generally move in the same direction.

Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows:

•The Company predominantly sells its natural gas production within the U.S., including to U.S. LNG export facilities, although a portion is sold to markets in Mexico. Most of the Company’s U.S. natural gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $3.92 per Mcf in 2021, up from $1.22 per Mcf in 2020.

•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.81 per Mcf in 2021, a 1 percent increase from 2020.

•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $12.96 per Mcf in 2021, a 306 percent increase from an average of $3.19 per Mcf in 2020.

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NGL Prices The Company’s U.S. NGL production, which accounted for 97 percent of the Company’s total 2021 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Crude Oil Revenues  

Crude oil revenues for 2021 totaled $4.6 billion, a $1.5 billion increase from the 2020 total of $3.1 billion. A 74 percent increase in average realized prices increased 2021 revenues by $2.3 billion compared to 2020, while 15 percent lower average daily production decreased revenues by $825 million. Average daily production in 2021 was 182 Mb/d, with prices averaging $68.97 per barrel. Crude oil sales accounted for 71 percent of the Company’s 2021 oil and gas production revenues and 47 percent of its worldwide production.

The Company’s worldwide crude oil production decreased 32 Mb/d compared to 2020, primarily a result of production decline across all countries driven by reduced drilling activity in the prior year, and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Revenues 

Natural gas revenues for 2021 totaled $1,207 million, a $609 million increase from the 2020 total of $598 million. A 118 percent increase in average realized prices increased 2021 revenues by $705 million compared to 2020, while 7 percent lower average daily production decreased revenues by $96 million. Average daily production in 2021 was 830 MMcf/d, with prices averaging $3.99 per Mcf. Natural gas sales accounted for 18 percent of the Company’s 2021 oil and gas production revenues and 36 percent of its worldwide production.

The Company’s worldwide natural gas production decreased 64 MMcf/d compared to 2020, 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 Revenues  

NGL revenues for 2021 totaled $706 million, a $373 million increase from the 2020 total of $333 million. A 141 percent increase in average realized prices increased 2021 revenues by $467 million compared to 2020, while 12 percent lower average daily production decreased revenues by $94 million. Average daily production in 2021 was 68 Mb/d, with prices averaging $28.48 per barrel. NGL sales accounted for 11 percent of the Company’s 2021 oil and gas production revenues and 17 percent of its worldwide production.

The Company’s worldwide NGL production decreased 9 Mb/d compared to 2020, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.

Altus Midstream Revenues

The Company beneficially owns approximately 79 percent of ALTM’s outstanding voting common stock. Altus owns and operates a midstream energy asset network in the Permian Basin of West Texas primarily to service the Company’s production from its Alpine High resource play, which commenced production in May 2017. On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction, and Apache’s ownership in ALTM will be reduced from approximately 79 percent to approximately 20 percent. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.

Altus Midstream primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2021 and 2020, Altus Midstream’s service revenues generated through its fee-based contractual arrangements with the Company totaled $127 million and $145 million, respectively. These affiliated revenues are eliminated upon consolidation. The decrease in revenue compared to the prior year was primarily driven by lower natural gas throughput volumes processed by Altus for the Company’s Alpine High production.

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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 increased $1.1 billion for the year ended December 31, 2021 from $398 million to $1.5 billion. Purchased oil and gas sales were offset by associated purchase costs of $1.6 billion and $357 million for the years ended December 31, 2021 and 2020, respectively. The increase is the result of sales volume growth associated with additional transport capacity and a more than doubling of the average gas sales price.

Operating Expenses

The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2021, 2020, and 2019. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Lease operating expenses	$	1,241	$	1,127	$	1,447
Gathering, processing, and transmission	264		274		306
Purchased oil and gas costs	1,580		357		142
Taxes other than income	204		123		207
Exploration	127		274		805
General and administrative	357		290		406
Transaction, reorganization, and separation	22		54		50
Depreciation, depletion, and amortization:
Oil and gas property and equipment	1,255		1,643		2,512
Gathering, processing, and transmission assets	64		76		105
Other assets	41		53		63
Asset retirement obligation accretion	113		109		107
Impairments	208		4,501		2,949
Financing costs, net	472		267		462

Lease Operating Expenses (LOE)

LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 47 percent of the Company’s total 2021 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2021, LOE increased $114 million, or 10 percent, compared to 2020. On a per-boe basis, LOE increased $1.75, or 25 percent, compared to 2020, from $7.00 per boe to $8.75 per boe. The increase in costs was driven by maintenance and turnaround costs in the North Sea, higher-priced emissions credits purchased in association with North Sea production, increased workover activity in the U.S., operating costs trending with commodity prices, inflation impacts, and overall higher labor costs that were heavily impacted by mark-to-market adjustments for stock-based compensation.

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Gathering, Processing, and Transmission (GPT)

GPT expenses include amounts paid to third-party carriers and to Altus Midstream for gathering and transmission services for the Company’s upstream natural gas production associated with its Alpine High play. GPT expenses also include midstream operating costs incurred by Altus Midstream. The following table presents a summary of these expenses:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Third-party processing and transmission costs	$	232	$	236	$	250
Midstream service affiliate costs	128		143		134
Upstream processing and transmission costs	360		379		384
Midstream operating expenses	32		38		56
Intersegment eliminations	(128)		(143)		(134)
Total Gathering, processing, and transmission	$	264	$	274	$	306

GPT costs decreased $10 million compared to 2020. Third-party processing and transmission costs decreased $4 million, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $15 million compared to 2020, primarily driven by lower throughput of natural gas volumes at Alpine High. Midstream operating expenses, incurred primarily by Altus, decreased $6 million compared to 2020, driven by continued improvements in operational efficiency as a result of transitioning from mechanical refrigeration units to Altus’ centralized Diamond cryogenic complex. The transition resulted in decreases in contract labor, equipment rentals, and chemical expenses.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $1.2 billion compared to 2020, and were primarily offset by associated sales totaling $1.5 billion for the year ended 2021, as further discussed above.

Taxes Other Than Income

Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes.

Taxes other than income increased $81 million compared to 2020, primarily from higher severance taxes driven by higher commodity prices.

Exploration Expenses

Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Unproved leasehold impairments	$	31	$	101	$	619
Dry hole expenses	55		110		57
Geological and geophysical expenses	8		20		59
Exploration overhead and other	33		43		70
Total Exploration	$	127	$	274	$	805

Exploration expenses decreased $147 million compared to 2020. Unproved leasehold impairments were $70 million lower than the prior year due to improved commodity prices and increased drilling plans in the U.S. Dry hole expense decreased $55 million, geological and geophysical expenses decreased $12 million, and exploration overhead and other expenses decreased $10 million compared to 2020, primarily resulting from decreased exploration activities compared to the prior year.

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General and Administrative (G&A) Expenses

G&A expenses increased $67 million compared to 2020, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price compared to the prior year, partially offset by lower overhead driven by organizational redesign efforts during 2019 and 2020.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $32 million compared to 2020, primarily driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.

In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed in 2020; however, additional reorganization costs related to ongoing consulting and separation activities in the Company’s international operations were incurred during 2021.

Depreciation, Depletion and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2021 decreased $388 million compared to 2020. The Company’s oil and gas property DD&A rate decreased $1.35 per boe in 2021 compared to 2020, from $10.20 per boe to $8.85 per boe. 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 depreciation decreased $12 million compared to 2020, driven by impairment charges recorded against the carrying value of the Company’s GPT facilities in Egypt during the first quarter of 2020.

Impairments

During 2021, the Company recorded asset impairments totaling $208 million. The charges include $160 million for Altus’ equity method interest in EPIC, as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination, $26 million in connection with inventory valuations in Egypt, and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

During 2020, the Company recorded asset impairments in connection with fair value assessments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S, Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $27 million for inventory and other miscellaneous assets, including lease assets and charges for the early termination of drilling rig leases.

The following table presents a summary of asset impairments recorded for 2021, 2020, and 2019:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil and gas proved property	$	—	$	4,319	$	1,484
GPT facilities	—		68		1,295
Equity method interests	160		—		—
Divested unproved properties and leasehold	—		—		149
Goodwill	—		87		—
Inventory and other	48		27		21
Total Impairments	$	208	$	4,501	$	2,949

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Financing Costs, Net

Financing costs incurred during the period comprised the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Interest expense	$	419	$	438	$	430
Amortization of debt issuance costs	8		8		7
Capitalized interest	—		(12)		(37)
Loss (gain) on extinguishment of debt	104		(160)		75
Interest income	(8)		(7)		(13)
Interest income from APA Corporation, net	(51)		—		—
Total Financing costs, net	$	472	$	267	$	462

Net financing costs increased $205 million compared to 2020, primarily the result of a $104 million loss on extinguishment of debt during 2021 and a $160 million gain on extinguishment of debt during 2020. Additionally, Apache recognized $51 million of interest income from APA related to the note payable by APA to Apache issued upon completion of the Holding Company Reorganization. Refer to Note 2—Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for more detail.

Provision for Income Taxes

Income tax expense increased $514 million from $64 million during 2020 to $578 million during 2021. The Company’s year-to-date 2021 effective income tax rate was primarily impacted by asset impairments and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During 2020, the Company’s 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 and 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. For additional information regarding income taxes, refer to Note 11—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

The Company and its subsidiaries are 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 (IRS) 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.

Potential Decommissioning Obligations on Sold Properties

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 such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, Apache could be required to perform such actions under applicable federal laws and regulations. In such event, Apache may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

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

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consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit backed by investment-grade counterparties to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

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

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

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

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

As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.

Insurance Program

The Company maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. The Company’s insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company’s insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect the Company against liability from all potential consequences and damages. Further, the Company does not have coverage in place for a variety of other risks including Gulf of Mexico named windstorm and business interruption. Service agreements, including drilling contracts, generally indemnify the Company for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

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The Company purchases multi-year political risk insurance from The Islamic Corporation for the Insurance of Investment and Export Credit Trade (ICIEC, an agency of the Islamic Development Bank) and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. In the aggregate, these insurance policies provide up to $750 million of coverage, subject to policy terms and conditions and a retention of approximately $500 million.

The Company also has an insurance policy with U.S. International Development Finance Corporation (DFC), which, subject to policy terms and conditions, provides up to $150 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed the Company on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent the Company from exporting its share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $60 million in reinsurance to DFC.

Future insurance coverage for the Company’s industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable.

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. The following is a discussion of the Company’s most critical accounting estimates.

Reserves Estimates

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Despite the inherent imprecision in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company’s supplemental oil and gas disclosures. For more information regarding the Company’s supplemental oil and gas disclosures, refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The Company has elected not to disclose probable and possible reserves or reserve estimates in this filing.

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Oil and Gas Exploration Costs

The Company accounts for its exploration and production activities using the successful efforts method of accounting. Costs of acquiring unproved and proved oil and gas leasehold acreage are capitalized. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are also capitalized. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. On a quarterly basis, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities and determines 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 recorded as dry hole expense and reported in exploration expense in the statement of consolidated operations. Otherwise, the costs of exploratory wells remain capitalized.

Offshore Decommissioning Contingency

The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Obligation to Decommission Sold Properties” above and in Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K. Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact the Company’s estimate of its contingent liability to decommission Legacy GOM Assets.

Impairment of Equity Method Interests

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

Altus recorded an impairment charge on its equity method interest in EPIC in the fourth quarter of 2021. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. The Company has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 7—Equity Method Interests, within Part IV, Item 15 of this Annual Report on Form 10-K for further details of Altus’ equity method interests. Negative revisions in future estimates of throughput volumes, revenue assumptions or costs related to the Altus’ equity method interests could lead to further impairments of such interests in future periods.

Long-Lived Asset Impairments

Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.

42

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.

To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.

Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

Over the past several years, the Company has experienced substantial volatility in commodity prices, which impacted its future development plans and operating cash flows. As such, material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities were recorded in 2020 and 2019. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

Asset Retirement Obligation (ARO)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea and Gulf of Mexico. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Income Taxes

The Company’s oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company’s deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

43

The Company regularly assesses and, if required, establishes accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law, and any new legislation. The Company believes that its accruals for uncertain tax positions are adequate in relation to the potential for any additional tax assessments.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.

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 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 beginning in early 2020.

The Company’s average crude oil realizations increased 74 percent to $68.97 per barrel in 2021 from $39.60 per barrel in 2020. The Company’s average natural gas price realizations increased 118 percent to $3.99 per Mcf in 2021 from $1.83 per Mcf in 2020. The Company’s average NGL realizations increased 141 percent to $28.48 per barrel in 2021 from $11.84 per barrel in 2020. Based on average daily production for 2021, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $66 million, a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $30 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $25 million.

The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of December 31, 2021, the Company had open natural gas derivatives, not designated as cash flow hedges, in a liability position with a fair value of approximately $10 million. A 10 percent increase in basis differential of the hedges would increase the liability by approximately $30 million, while a 10 percent decrease in basis differential of the hedges would move the derivatives to an asset position of approximately $21 million. These fair value changes assume volatility based on prevailing market parameters as of December 31, 2021. Refer to Note 5—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report Form 10-K for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

At December 31, 2021, Apache had $6.3 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.07 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt. The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the Apache and Altus Midstream LP credit facilities. As of December 31, 2021, the Company had approximately $279 million in cash and cash equivalents, approximately 62 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2021, there were $542 million and $657 million of borrowings outstanding under the Apache Corporation and Altus Midstream LP revolving credit facilities, respectively. A change in the interest rate applicable to short-term investments and credit facility borrowings would have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.

44

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 $3 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 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. As of December 31, 2021, the Company had outstanding foreign exchange contracts with a total notional amount of £180 million that are used to reduce its exposure to fluctuating foreign exchange rates for the British pound. A 10 percent strengthening of the British pound against the U.S. dollar would result in a foreign currency net gain of $20 million, while a 10 percent weakening of the British pound against the U.S. dollar would result in a loss of $14 million as of December 31, 2021.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-66 in Part IV, Item 15 of this Annual Report on Form 10-K and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2021, 2020, and 2019, included in this Annual Report on Form 10-K, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

ITEM 9A. 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 December 31, 2021, the end of the period covered by this Annual Report on Form 10-K. 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.

45

Management’s Annual Report on Internal Control Over Financial Reporting

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Part IV, Item 15 of this Annual Report on Form 10-K.

This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm on the Company’s internal control over financial reporting. As a non-accelerated filer, the management report called for by Item 308(a) of Regulation S-K is not subject to attestation by the Company’s independent registered public accounting firm.

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2021, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

46

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Accountant fees and services paid to Ernst & Young LLP, the Company’s independent auditors, are included in amounts paid by APA on behalf of Apache. Information on APA’s principal accountant fees and services is set forth under the caption “Ratification of Appointment of Independent Auditors” in the APA Proxy Statement incorporated herein by reference.

47

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)Documents included in this report:

1. Financial Statements

 

Report of management on internal control over financial reporting	F-1
Report of independent registered public accounting firm (PCAOB ID: 42)	F-2
Statement of consolidated operations for each of the three years in the period ended December 31, 2021	F-5
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2021	F-6
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2021	F-7
Consolidated balance sheet as of December 31, 2021 and 2020	F-8
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2021	F-9
Notes to consolidated financial statements	F-10

2.	Financial Statement Schedules
	Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.

3. Exhibits

48

EXHIBIT NO.		DESCRIPTION
2.1	–	Agreement and Plan of Merger, dated as of March 1, 2021, by and among Registrant, APA Corporation, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.1	–	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as attached as Annex A to the Certificate of Merger of APA Merger Sub, Inc. with and into Registrant, filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.2	–	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated June 7, 2021, filed with the Secretary of State of the State of Delaware on June 10, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 14, 2021, SEC File No. 001-4300).
3.3	–	Amended and Restated Bylaws of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
4.1	–	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).
4.2	–	Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.3	–	Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.4	–	Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.5	–	Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.6	–	Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.7	–	Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.8	–	Form of 4.375% Notes due 2028 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on August 16, 2018, SEC File No. 001-4300).
4.9	–	Form of 4.625% Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on August 6, 2020, SEC File No. 001-4300).
4.10	–	Form of 4.875% Notes due 2027 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, filed on August 6, 2020, SEC File No. 001-4300).
4.11	–	Form of 7.75% Notes due December 15, 2029 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K/A, filed on December 14, 1999, SEC File No. 001-4300).
4.12	–	Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.13	–	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.14	–	Second Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank, formerly Chemical Bank), as trustee under Indenture, dated as of February 15, 1996, as previously amended and supplemented (incorporated by reference to Exhibit 4.15 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.15	–	Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
4.16	–	Supplemental Indenture, dated as of August 14, 2017, among Apache Finance Canada Corporation, Apache Corporation, and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q filed November 3, 2017, SEC File No. 001-04300).

49

EXHIBIT NO.		DESCRIPTION
4.17	–	Second Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation (as successor to Apache Finance Canada Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee under Indenture, dated as of November 23, 1999, as previously amended and supplemented (incorporated by reference to Exhibit 4.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.18	–	Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
4.19	–	Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation and Wells Fargo Bank, National Association, as trustee under Indenture, dated as of May 19, 2011 (incorporated by reference to Exhibit 4.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.20	–	Indenture, dated August 14, 2018, by and between Apache Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Registrant’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 filed August 14, 2018, SEC File No. 333-219345).
10.1	–	Credit Agreement, dated as of March 14, 2018, among Apache Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, Citibank, N.A., Royal Bank of Canada, HSBC Bank USA, National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd, Wells Fargo Bank, National Association, Goldman Sachs Bank USA, The Toronto-Dominion Bank, New York Branch, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed March 19, 2018).
†10.2	–	Assignment and Assumption Agreement, dated as of March 1, 2021, by and between APA Corporation and Registrant (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
†10.3	–	Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.4	–	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 12, 2020, effective August 1, 2020 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, SEC File No. 001-4300).
†10.5	–	Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
†10.6	–	Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.7	–	Amendment to Apache Corporation Non-Qualified Restorative Retirement Savings Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
*23.1	–	Consent of Ryder Scott Company, L.P., Petroleum Consultants.
*24.1	–	Power of Attorney (included as a part of the signature pages to this report).
*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.
*99.1	–	Report of Ryder Scott Company, L.P., Petroleum Consultants.
*101.INS	–	Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*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.

50

EXHIBIT NO.		DESCRIPTION
*101.PRE	–	Inline XBRL Presentation Linkbase Document.
*104	–	Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).

* Filed herewith.

† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.

NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.

ITEM 16. FORM 10-K SUMMARY

None.

51

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

                                APACHE CORPORATION

/s/ John J. Christmann IV                    

John J. Christmann IV

Chief Executive Officer and President

Dated: February 22, 2022

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint John J. Christmann IV, Stephen J. Riney, and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ John J. Christmann IV John J. Christmann IV	Director, Chief Executive Officer, and President (principal executive officer)	February 22, 2022
/s/ Stephen J. Riney Stephen J. Riney	Executive Vice President and Chief Financial Officer (principal financial officer)	February 22, 2022
/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Senior Vice President, Chief Accounting Officer, and Controller (principal accounting officer)	February 22, 2022
/s/ Clay Bretches Clay Bretches	Director and Executive Vice President, Operations	February 22, 2022
/s/ David A. Pursell David A. Pursell	Director and Executive Vice President, Development	February 22, 2022
/s/ Mark D. Maddox Mark D. Maddox	Director and Senior Vice President, Administration	February 22, 2022

52

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.

Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2021.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.

/s/  John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

/s/  Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

/s/  Rebecca A. Hoyt

Senior Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas

February 22, 2022

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Apache Corporation:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries (the Company) as of December 31, 2021 and 2020, the related statements of consolidated operations, comprehensive income (loss), cash flows and changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depreciation, depletion and amortization of property and equipment

Description of the Matter

At December 31, 2021, the carrying value of the Company’s property and equipment was $8,059 million, and depreciation, depletion and amortization (DD&A) expense was $1,360 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers.

F-2

	Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for select properties as of December 31, 2021. Auditing the Company’s DD&A calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates for select properties. In addition, in assessing whether we can use the work of the engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s development plan and the availability of capital relative to the development plan. We also tested the mathematical accuracy of the DD&A calculation, including comparing the oil and gas reserve amounts used in the calculation to the Company’s reserve reports.
	Accounting for asset retirement obligation for the North Sea segment
Description of the Matter	At December 31, 2021, the asset retirement obligation (ARO) balance totaled $2,130 million. As further described in Note 9, the Company’s ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs and higher estimation uncertainty related to the timing of settlements and settlement amounts. Auditing the Company’s ARO for the North Sea segment is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.

F-3

How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation. To test the ARO for the North Sea segment, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs. Additionally, we compared assumptions for the timing of settlements to production forecasts. We also involved our internal specialists in testing the underlying retirement cost estimates.
	Accounting for decommissioning contingency for sold Gulf of Mexico properties
Description of the Matter	At December 31, 2021, the decommissioning contingency for sold Gulf of Mexico properties (decommissioning contingency) balance totaled $1,186 million. As further described in Note 12, the Company’s decommissioning contingency reflects the estimated undiscounted potential liability to fund decommissioning of the sold Gulf of Mexico properties. The estimation of the decommissioning contingency requires significant judgment given the magnitude and higher estimation uncertainty of the expected retirement costs. Auditing the Company’s decommissioning contingency is complex and highly judgmental because of the significant estimation required by management in determining the decommissioning contingency. In particular, the estimate was sensitive to retirement cost and duration estimates, which are subjective assumptions affected by expectations about future market and economic conditions.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its decommissioning contingency estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the contingency. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation. To test the decommissioning contingency, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost and duration estimates. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs as well as current bids obtained from service providers. We also involved our internal specialists in testing the underlying retirement cost and duration estimates.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.

Houston, Texas

February 22, 2022

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2021		2020		2019
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	6,498	$	4,037	$	6,315
Purchased oil and gas sales	1,487		398		176
Total revenues	7,985		4,435		6,491
Derivative instrument gains (losses), net	94		(223)		(35)
Gain on divestitures, net	67		32		43
Loss on previously sold Gulf of Mexico properties	(446)		—		—
Other, net	228		64		54
	7,928		4,308		6,553
OPERATING EXPENSES:
Lease operating expenses	1,241		1,127		1,447
Gathering, processing, and transmission	264		274		306
Purchased oil and gas costs	1,580		357		142
Taxes other than income	204		123		207
Exploration	127		274		805
General and administrative	357		290		406
Transaction, reorganization, and separation	22		54		50
Depreciation, depletion, and amortization	1,360		1,772		2,680
Asset retirement obligation accretion	113		109		107
Impairments	208		4,501		2,949
Financing costs, net	472		267		462
	5,948		9,148		9,561
NET INCOME (LOSS) BEFORE INCOME TAXES	1,980		(4,840)		(3,008)
Current income tax provision	652		176		660
Deferred income tax provision (benefit)	(74)		(112)		14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	1,402		(4,904)		(3,682)
Net income (loss) attributable to noncontrolling interest - Egypt	174		(121)		167
Net income (loss) attributable to noncontrolling interest - Altus	4		1		(334)
Net income attributable to Altus Preferred Unit limited partners	162		76		38
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	$	1,062	$	(4,860)	$	(3,553)

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

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	1,402	$	(4,904)	$	(3,682)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	7		(2)		13
Share of equity method interests other comprehensive income (loss)	1		—		(1)
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	1,410		(4,906)		(3,670)
Comprehensive income (loss) attributable to noncontrolling interest - Egypt	174		(121)		167
Comprehensive income (loss) attributable to noncontrolling interest - Altus	4		1		(334)
Comprehensive income attributable to Altus Preferred Unit limited partners	162		76		38
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	$	1,070	$	(4,862)	$	(3,541)

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$	1,402	$	(4,904)	$	(3,682)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	(69)		87		44
Gain on divestitures, net	(67)		(32)		(43)
Exploratory dry hole expense and unproved leasehold impairments	86		211		676
Depreciation, depletion, and amortization	1,360		1,772		2,680
Asset retirement obligation accretion	113		109		107
Impairments	208		4,501		2,949
Provision for (benefit from) deferred income taxes	(74)		(112)		14
Loss (gain) from extinguishment of debt	104		(160)		75
Loss on previously sold Gulf of Mexico properties	446		—		—
Other	(23)		102		50
Changes in operating assets and liabilities:
Receivables	(393)		149		133
Inventories	(9)		19		(41)
Drilling advances and other current assets	60		(29)		30
Deferred charges and other long-term assets	(42)		(13)		—
Accounts payable	205		(167)		(5)
Accounts payable to APA Corporation	40		—		—
Accrued expenses	127		(163)		(84)
Deferred credits and noncurrent liabilities	31		18		(36)
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,505		1,388		2,867
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(934)		(1,270)		(2,594)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(3)		(28)		(327)
Leasehold and property acquisitions	(9)		(4)		(40)
Contributions to Altus equity method interests	(28)		(327)		(501)
Acquisition of Altus equity method interests	—		—		(671)
Proceeds from asset divestitures	256		166		718
Other	52		(3)		(31)
NET CASH USED IN INVESTING ACTIVITIES	(666)		(1,466)		(3,446)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	392		150		—
Proceeds from Altus credit facility	33		228		396
Proceeds from note payable to APA Corporation, net	78		—		—
Fixed rate debt borrowings	—		1,238		989
Payments on fixed-rate debt	(1,795)		(1,243)		(1,150)
Distributions to noncontrolling interest - Egypt	(279)		(91)		(305)
Distributions to Altus Preferred Unit limited partners	(46)		(23)		—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	—		—		611
Distributions to APA Corporation	(1,182)		—		—
Dividends paid	(9)		(123)		(376)
Treasury stock activity, net	—		1		2
Other	(14)		(44)		(55)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(2,822)		93		112
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	17		15		(467)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262		247		714
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	279	$	262	$	247
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	442	$	419	$	394
Income taxes paid, net of refunds	$	633	$	212	$	649

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2021		2020
	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($132 and $24 related to Altus VIE)	$	279	$	262
Receivables, net of allowance of $109 and $95	1,390		908
Other current assets (Note 6) ($9 and $5 related to Altus VIE)	649		676
Accounts receivable from APA Corporation	77		—
	2,395		1,846
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:	40,474		41,819
Gathering, processing, and transmission facilities ($209 and $206 related to Altus VIE)	673		670
Other ($3 and $3 related to Altus VIE)	1,126		1,140
Less: Accumulated depreciation, depletion, and amortization ($25 and $13 related to Altus VIE)	(34,213)		(34,810)
	8,060		8,819
OTHER ASSETS:
Equity method interests (Note 7) ($1,365 and $1,555 related to Altus VIE)	1,365		1,555
Decommissioning security for sold Gulf of Mexico properties (Note 12)	640		—
Deferred charges and other ($6 and $5 related to Altus VIE)	581		526
Note receivable from APA Corporation (Note 2)	1,352		—
	$	14,393	$	12,746
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable ($12 and $6 related to Altus VIE)	$	651	$	444
Note payable to APA Corporation (Note 2)	195		—
Current debt	215		2
Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)	1,170		862
	2,231		1,308
LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)	7,295		8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	148		215
Asset retirement obligation ($68 and $64 related to Altus VIE)	2,089		1,888
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	1,086		—
Other ($67 and $144 related to Altus VIE)	572		602
	3,895		2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 14)	712		608
EQUITY (DEFICIT):
Common stock, $0.625 par, 1,000 and 860,000,000 shares authorized, 1,000 and 418,429,375 shares issued, respectively	—		262
Paid-in capital	8,677		11,735
Accumulated deficit	(9,317)		(10,461)
Treasury stock, at cost, 0 and 40,946,745 shares, respectively	—		(3,189)
Accumulated other comprehensive income	22		14
DEFICIT ATTRIBUTABLE TO APA CORPORATION	(618)		(1,639)
Noncontrolling interest - Egypt	820		925
Noncontrolling interest - Altus	58		69
TOTAL EQUITY (DEFICIT)	260		(645)
	$	14,393	$	12,746

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

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

	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income (Loss)		PARENT COMPANY EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)
BALANCE AT DECEMBER 31, 2018	$	—	$	260	$	12,106	$	(2,048)	$	(3,192)	$	4	$	7,130	$	1,682	$	8,812
Net loss attributable to APA Corporation	—		—		—		(3,553)		—		—		(3,553)		—		(3,553)
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		167		167
Net loss attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		(334)		(334)
Issuance of Altus Preferred Units	517		—		—		—		—		—		—		—		—
Net income attributable to Altus Preferred Unit limited partners	38		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(305)		(305)
Common dividends ($1.00 per share)	—		—		(376)		—		—		—		(376)		—		(376)
Common stock activity, net	—		1		(22)		—		—		—		(21)		—		(21)
Compensation expense	—		—		61		—		—		—		61		—		61
Other	—		—		—		—		2		12		14		—		14
BALANCE AT DECEMBER 31, 2019	$	555	$	261	$	11,769	$	(5,601)	$	(3,190)	$	16	$	3,255	$	1,210	$	4,465
Net loss attributable to APA Corporation	—		—		—		(4,860)		—		—		(4,860)		—		(4,860)
Net loss attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(121)		(121)
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		1		1
Distributions paid to Altus Preferred Unit limited partners	(23)		—		—		—		—		—		—		—		—
Net income attributable to Altus Preferred Unit limited partners	76		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(91)		(91)
Common dividends ($0.10 per share)	—		—		(38)		—		—		—		(38)		—		(38)
Common stock activity, net	—		1		(18)		—		—		—		(17)		—		(17)
Compensation expense	—		—		23		—		—		—		23		—		23
Other	—		—		(1)		—		1		(2)		(2)		(5)		(7)
BALANCE AT DECEMBER 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)
Net income attributable to APA Corporation	—		—		—		1,062		—		—		1,062		—		1,062
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		174		174
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		4		4
Net income attributable to Altus Preferred Unit limited partners	162		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	(46)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(279)		(279)
Distributions to APA Corporation	—		—		(890)		—		—		—		(890)		—		(890)
Common dividends ($0.025 per share)	—		—		(9)		—		—		—		(9)		—		(9)
APA Corporation share exchange	—		(262)		(2,927)		—		3,189		—		—		—		—
Holding Company Reorganization	—		—		757		82		—		—		839		—		839
Other	—		—		11		—		—		8		19		(15)		4
BALANCE AT DECEMBER 31, 2021	$	712	$	—	$	8,677	$	(9,317)	$	—	$	22	$	(618)	$	878	$	260

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

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations

Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Apache’s midstream business (Altus Midstream) 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.

On January 4, 2021, Apache announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the APA’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. Refer to Note 2—Transactions with Parent Affiliate for more detail.

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.

Principles of Consolidation

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

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. ALTM is consolidated and qualifies as a variable interest entity (VIE) under GAAP. Additionally, in November of 2021, the Company determined that a limited partnership and Apache subsidiary, which has control over Apache’s Egyptian operations, qualifies as a VIE under GAAP. Apache consolidates the activities of ALTM and Apache’s Egyptian operations because it has concluded that Apache’s subsidiaries have a controlling financial interest in ALTM and APA’s Egyptian operations, respectively, and were determined to be the primary beneficiaries of the VIEs. Additionally, the assets of ALTM may only be used to settle obligations of ALTM. There is no recourse to the Company for ALTM’s liabilities.

Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate 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. The Company regularly reassesses whether changes in the facts and circumstances regarding the Company’s involvement with a VIE could cause a change in its conclusions related to consolidation. Changes in consolidation status, if any, are applied prospectively.

On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 14—Redeemable Noncontrolling Interest — Altus for further detail.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Investments in which the Company holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company’s proportionate share of the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 7—Equity Method Interests for further detail.

Use of Estimates

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

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 3—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation), the estimate of income taxes (refer to Note 11—Income Taxes), the estimation of the contingent liability representing Apache’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 12—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited)).

Fair Value Measurements

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

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

Recurring fair value measurements are presented in further detail in Note 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, Note 13—Retirement and Deferred Compensation Plans, and Note 14—Redeemable Noncontrolling Interest — Altus.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments:

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil and gas proved property	$	—	$	4,319	$	1,484
Gathering, processing, and transmission facilities	—		68		1,295
Equity method interests	160		—		—
Divested unproved properties and leasehold	—		—		149
Goodwill	—		87		—
Inventory and other	48		27		21
Total Impairments	$	208	$	4,501	$	2,949

For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in the EPIC crude oil pipeline (EPIC) as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 3—Acquisitions and Divestitures for further detail on the BCP Business Combination. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with non-recurring 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 of $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied 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 in the first quarter of 2020.

During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S.

During the fourth quarter of 2019, following a material reduction to planned investment in Apache’s Alpine High development, the Company recorded impairments totaling $1.4 billion for its Alpine High proved properties and upstream infrastructure which were written down to their fair values. Altus separately assessed its long-lived infrastructure assets for impairment based on expected reductions to future throughput volumes from Alpine High. Altus subsequently recorded impairments totaling $1.3 billion on its GPT facilities. 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.”

Separate from the Company’s Alpine High and Altus impairments, Apache entered into agreements to sell certain of its assets in the Western Anadarko Basin in Oklahoma and Texas. As a result of these agreements, a separate impairment analysis was performed for each of the assets within the disposal groups. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments in the second and fourth quarters of 2019 totaling $255 million, including $101 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. For more information regarding this transaction, refer to Note 3—Acquisitions and Divestitures.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Revenue Recognition

Upstream

The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.

The Company’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

On December 27, 2021, the Company announced the ratification of a modernized PSC with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The Apache subsidiary that became the sole Contractor under the PSC is owned by an Apache-operated joint venture owned two-thirds by Apache and one-third by Sinopec.

Refer to Note 18—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Altus Midstream

The Company’s Altus Midstream segment is operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generates revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on Apache’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represents a single, distinct performance obligation on behalf of Altus that is satisfied over time. In accordance with the terms of these agreements, Altus primarily receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is primarily measured using the output method and recognized in the amount to which Altus has the right to invoice, as performance completed to date corresponds directly with the value to its customers. For the periods presented, Altus Midstream segment revenues were primarily attributable to sales between Altus and Apache, which are fully eliminated upon consolidation.

Payment Terms and Contract Balances

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, totaled $956 million and $670 million as of December 31, 2021 and 2020, respectively.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2021 and 2020, the Company had $279 million and $262 million, respectively, of cash and cash equivalents, of which approximately $132 million and $24 million, respectively, was held by Altus. The Company had no restricted cash as of December 31, 2021 and 2020.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. The Company adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

The following table presents changes to the Company’s allowance for credit loss:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Allowance for credit loss at beginning of year	$	95	$	88	$	92
Additional provisions for the year	19		7		3
Uncollectible accounts written off, net of recoveries	(5)		—		(7)
Allowance for credit loss at end of year	$	109	$	95	$	88

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.

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.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 2019.

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Proved properties:
U.S.	$	—	$	3,938	$	1,484
Egypt	—		374		—
North Sea	—		7		—
Total proved properties	$	—	$	4,319	$	1,484
Unproved properties:
U.S.	$	22	$	92	$	760
Egypt	8		8		8
North Sea	1		1		—
Total unproved properties	$	31	$	101	$	768

Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively.

Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 3—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission Facilities

GPT facilities totaled $673 million and $670 million at December 31, 2021 and 2020, respectively, with accumulated depreciation for these assets totaling $386 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity to those fields.

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

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

As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment totaled $1.1 billion at each of December 31, 2021 and 2020, with accumulated depreciation for these assets totaling $901 million and $864 million at December 31, 2021 and 2020, respectively.

Asset Retirement Costs and Obligations

The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Capitalized Interest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense.

The following presents the changes to goodwill for the years ended 2020 and 2019:

	Egypt		Total
	(In millions)
Goodwill at December 31, 2018	$	87	$	87
Impairments	—		—
Goodwill at December 31, 2019	87		87
Impairments	(87)		(87)
Goodwill at December 31, 2020	$	—	$	—

Reductions in estimated net present value of expected future cash flows from oil and gas properties during 2020 resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of this assessment, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in 2020. This goodwill impairment was recorded in “Impairments” in the Company’s statement of consolidated operations.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Equity Method Interests

The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company.

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. In the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the announced BCP Business Combination, determined the current fair value of its investment in EPIC was below carrying value. Altus subsequently determined that this loss in value to be other than temporary. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in EPIC. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. Altus has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 7—Equity Method Interests for further details of the Company’s equity method interests.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 12—Commitments and Contingencies.

Derivative Instruments and Hedging Activities

The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.

All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 5—Derivative Instruments and Hedging Activities for further information.

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

Stock-Based Compensation

Prior to consummation of the Holding Company Reorganization, Apache granted various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on APA’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s previous stock-based compensation plans, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 organization 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 $17 million of reorganization costs were incurred during the year ended December 31, 2021, primarily related to ongoing consulting and separation activities in the Company’s international operations.

The Company recorded $22 million, $54 million, and $50 million of TRS costs in 2021, 2020, and 2019, respectively. TRS costs incurred in 2021 relate to $11 million for consulting costs associated with the reorganization, $6 million of separation costs associated with the reorganization, and $5 million for costs associated with the BCP Business Combination. TRS costs incurred in 2020 relate to $51 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs. TRS costs incurred in 2019 associated with the reorganization include $26 million for employee termination benefits and $2 million for consulting fees. The Company also incurred $15 million of expenses for employee termination benefits and office closures associated with other reorganization efforts and $7 million for consulting and legal fees on various transactions throughout 2019.

New Pronouncements Issued But Not Yet Adopted

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by the discontinuation of the London Interbank Offered Rate (LIBOR) or by another reference rate expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarified the scope and application of the original guidance. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. The Company is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.

In August 2020, the FASB issued ASU 2020-06, “Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40)” to improve financial reporting associated with accounting for convertible instruments and contracts in an entity’s own equity. This update is effective for the Company beginning in the first quarter of 2022 using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company does not believe it will have a material impact on its financial statements.

2.    TRANSACTIONS WITH PARENT AFFILIATE

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

The Company recognized interest income of approximately $51 million on this note during 2021, which is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2021 to PIK pursuant to the note.

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

The Company continues to provide administrative and support operations to APA related to activities performed for the Suriname and Dominican Republic subsidiaries. The Company is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company in connection with its role as service provider. All reimbursements are based on actual costs incurred and no market premium is applied by the Company to APA. The Company incurred $17 million in reimbursable corporate overhead charges during 2021.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In August 2021, Apache entered into a promissory note with APA under which Apache may borrow up to $250 million from APA at APA’s discretion. The note has a term of one year, maturing on August 4, 2022, and bears interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of December 31, 2021, there was $195 million outstanding under this note, which is reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet.

3.   ACQUISITIONS AND DIVESTITURES

2022 Activity

In February 2022, the Company entered into an agreement to sell certain non-core mineral rights in the Delaware Basin for cash consideration of approximately $805 million, subject to customary post-closing adjustments. The transaction is expected to close in late February 2022, subject to regulatory approvals.

2021 Activity

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

During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions.

During 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.

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

As consideration for the transaction, ALTM will issue 50 million shares of Class C Common Stock (and its subsidiary, Altus Midstream LP, will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.

2020 Activity

During 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million. Also during 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 $87 million, and recognized a gain of $13 million.

2019 Activity

U.S. Divestitures and Leasehold, Property, and Other Acquisitions

In the third quarter of 2019, the Company completed the sale of non-core assets in the Western Anadarko Basin of Oklahoma and Texas for aggregate cash proceeds of approximately $322 million and the assumption of asset retirement obligations of $49 million. These assets met the criteria to be classified as held for sale in the second quarter of 2019. Accordingly, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The transaction closed in the third quarter of 2019, and the Company recognized a $7 million loss in connection with the sale.

In the second quarter of 2019, the Company completed the sale of certain non-core assets in Oklahoma that had a net carrying value of $206 million for aggregate cash proceeds of approximately $223 million. The Company recognized a $17 million gain in connection with the sale.

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million. The Company recognized a net gain of approximately $33 million upon closing of these transactions.

During 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $40 million.

Suriname Joint Venture Agreement

In December 2019, prior to the Holding Company Reorganization, when Apache’s subsidiaries held interests in Suriname, 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.

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.

4.   CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2021, 2020, and 2019. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Capitalized well costs at beginning of year	$	197	$	141	$	159
Additions pending determination of proved reserves	62		226		286
Divestitures and other	(163)		(38)		(100)
Reclassifications to proved properties	(40)		(56)		(179)
Charged to exploration expense	(10)		(76)		(25)
Capitalized well costs at end of year	$	46	$	197	$	141

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:

	2021		2020		2019
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	13	$	184	$	108
Exploratory well costs capitalized for a period greater than one year	33		13		33
Capitalized well costs at end of year	$	46	$	197	$	141
Number of projects with exploratory well costs capitalized for a period greater than one year	9		5		2

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 reserves can be attributed to these projects. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling were $33 million at December 31, 2021, with $24 million related to exploration and appraisal well activity in the North Sea, where subsurface evaluation and project viability assessment is ongoing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing.

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2020 and 2019, relate to onshore projects in Egypt and the U. S. Drilling activity and testing has continued for several of these projects in Egypt throughout 2021, and are currently being evaluated for potential development. The costs related to the U.S. projects were charged to exploration expense based on management’s assessment and development efforts.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2021, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:

	Total		2020		2019		2018 and Prior
	(In millions)
Egypt	$	9	$	—	$	—	$	9
North Sea	24		24		—		—
	$	33	$	24	$	—	$	9

5.    DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, 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 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 December 31, 2021, the Company had derivative positions with 10 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 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
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

Foreign Currency Derivative Instruments

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

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Embedded Derivatives

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP issued and sold the 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 14—Redeemable Noncontrolling Interest — Altus.

Pipeline Capacity Embedded Derivatives

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

Fair Value Measurements

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2021
Liabilities:
Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Pipeline capacity embedded derivatives	—		46		—		46		—		46
Preferred Units embedded derivative	—		—		57		57		—		57
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivatives	—		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.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The fair value of the Preferred Units embedded derivative is calculated using an income approach, a Level 3 fair value measurement. The fair value 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, any anticipated early redemptions of the Preferred Units, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the December 31, 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 at December 31, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	57	Option Model	Altus’ Imputed Interest Rate	5.54-11.21%
				Interest Rate Volatility	40.08%

In addition, no early redemptions of the Preferred Units were assumed for the December 31, 2020 valuation. As a result of the announced BCP Business Combination and associated publicly filed information, the December 31, 2021 valuation assumed 250,000 Preferred Units would be redeemed before the Preferred Unit holders had the right to exercise their exchange option. This early redemption assumption significantly reduced the value of the derivative liability year over year.

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of December 31, 2021, while a one percent decrease would lead to a similar decrease in value as of December 31, 2021. The assumed expected timing until exercise of the exchange option at December 31, 2021 was 4.45 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:

	For the Year Ended December 31,
	2021		2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	4	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	109		192
Total derivative liabilities	$	113	$	192

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 Year Ended December 31,
	2021		2020		2019
	(In millions)
Realized:
Commodity derivative instruments	$	25	$	(135)	$	27
Foreign currency derivative instruments	—		(1)		—
Treasury-lock	—		—		(18)
Realized gain (loss), net	25		(136)		9
Unrealized:
Commodity derivative instruments	(20)		11		(44)
Pipeline capacity embedded derivatives	7		(61)		8
Foreign currency derivative instruments	—		(1)		1
Preferred Units embedded derivative	82		(36)		(9)
Unrealized gain (loss), net	69		(87)		(44)
Derivative instrument gains (losses), net	$	94	$	(223)	$	(35)

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

The Company seeks to maintain a balance between “first of month” and “gas daily pricing” for its U.S. natural gas portfolio and sales activities in a given month as part of its ordinary course of business. This is typically implemented through a combination of physical and financial contracts that settle monthly.

6.    OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of December 31:

	2021		2020
	(In millions)
Inventories	$	438	$	492
Drilling advances	55		113
Prepaid assets and other	56		71
Current decommissioning security for sold Gulf of Mexico assets	100		—
Total Other current assets	$	649	$	676

7.    EQUITY METHOD INTERESTS

As of December 31, 2021 and 2020, Apache, through its ownership of Altus, has 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.

	Interest		2021		2020
			(In millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	274	$	284
EPIC Crude Holdings, LP	15.0	%	—		176
Permian Highway Pipeline LLC	26.7	%	630		615
Shin Oak Pipeline (Breviloba, LLC)	33.0	%	461		480
Total Altus equity method interests			$	1,365	$	1,555

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2021 and 2020, unamortized basis differences included in the equity method interest balances were $34 million and $38 million, respectively. These amounts represent differences in Altus’ initial costs paid to acquire the equity method interests and its initial underlying equity in the respective entities, as well as capitalized interest related to Permian Highway Pipeline (PHP) construction costs. Unamortized basis differences are amortized into equity income (loss) over the useful lives of the underlying pipeline assets when they are placed into service.

The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2021 and 2020:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2019	$	291	$	163	$	311	$	493	$	1,258
Capital contributions	2		29		296		—		327
Distributions	(51)		—		—		(46)		(97)
Capitalized interest(1)	—		—		8		—		8
Equity income (loss), net	42		(16)		—		33		59
Balance at December 31, 2020	284		176		615		480		1,555
Capital contributions	—		2		26		—		28
Distributions	(50)		—		(74)		(49)		(173)
Equity income (loss), net	40		(19)		63		30		114
Accumulated other comprehensive loss	—		1		—		—		1
Impairment(2)	—		(160)		—		—		(160)
Balance at December 31, 2021	$	274	$	—	$	630	$	461	$	1,365

(1)Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million of related interest expense during 2020, which is included in the basis of the PHP equity interest.

(2)The Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies for further details on this impairment charge.

Summarized Combined Financial Information

The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis):

	For the Year Ended December 31,
	2021		2020		2019(1)
	(In millions)
Operating revenues	$	1,082	$	707	$	302
Operating income	548		331		121
Net income	468		256		120
Other comprehensive income (loss)	4		3		(8)

(1)Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the full year ended December 31, 2019 for comparability.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31:

	2021		2020
	(In millions)
Current assets	$	280	$	260
Noncurrent assets	7,445		7,678
Total assets	$	7,725	$	7,938
Current liabilities	$	153	$	206
Noncurrent liabilities	1,193		1,191
Equity	6,379		6,541
Total liabilities and equity	$	7,725	$	7,938

8.    OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of December 31:

	2021		2020
	(In millions)
Accrued operating expenses	$	129	$	91
Accrued exploration and development	206		167
Accrued compensation and benefits	292		170
Accrued interest	107		140
Accrued income taxes	28		25
Current asset retirement obligation	41		56
Current operating lease liability	99		116
Current decommissioning contingency for sold Gulf of Mexico properties	100		—
Other	168		97
Total Other current liabilities	$	1,170	$	862

9.    ASSET RETIREMENT OBLIGATION

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

	For the Year Ended December 31,
	2021		2020
	(In millions)
Asset retirement obligation at beginning of the year	$	1,944	$	1,858
Liabilities incurred	3		10
Liabilities divested	(44)		(26)
Liabilities settled	(32)		(30)
Accretion expense	113		109
Revisions in estimated liabilities	146		23
Asset retirement obligation at end of the year	2,130		1,944
Less current portion	(41)		(56)
Asset retirement obligation, long-term	$	2,089	$	1,888

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2021 and 2020, the Company recorded $3 million and $10 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2021, approximately $146 million net abandonment costs were revised upward to reflect changes in estimates of higher current activity costs and long-term inflation assumptions, primarily in the U.S. During 2020, approximately $23 million net abandonment costs were revised upward to reflect changes in estimates of timing and costs, primarily in the North Sea.

10.    DEBT AND FINANCING COSTS

Overview

The debt of Apache and Altus Midstream LP is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company to repurchase outstanding notes and debentures upon certain changes in control. None of the indentures contain prepayment obligations in the event of a decline in credit ratings.

On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

On June 21, 2019, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases.

On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s senior revolving credit facility, and for general corporate purposes.

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

During 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under the Company’s revolving credit facility.

During the quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations.

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

	December 31,
	2021		2020
	(In millions)
3.25% notes due 2022(1)(2)	$	213	$	213
2.625% notes due 2023(2)	123		123
4.625% notes due 2025(2)	500		500
7.7% notes due 2026	79		79
7.95% notes due 2026	133		133
4.875% due 2027(2)	378		750
4.375% notes due 2028(2)	703		993
7.75% notes due 2029(2)(3)	235		235
4.25% notes due 2030(2)	580		580
6.0% notes due 2037(2)	443		443
5.1% notes due 2040(2)	1,333		1,333
5.25% notes due 2042(2)	399		399
4.75% notes due 2043(2)	428		1,133
4.25% notes due 2044(2)	221		559
7.375% debentures due 2047	150		150
5.35% notes due 2049(2)	387		390
7.625% debentures due 2096	39		39
Notes and debentures before unamortized discount and debt issuance costs(4)	6,344		8,052
Commercial paper	—		—
Altus credit facility(5)	657		624
Apache credit facility(5)	542		150
Finance lease obligations	36		38
Unamortized discount	(30)		(35)
Debt issuance costs	(39)		(57)
Total debt	7,510		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,295	$	8,770

(1)On January 18, 2022, Apache redeemed the 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.

(2)These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.

(3)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.

(4)The fair values of Apache’s notes and debentures were $7.1 billion and $8.5 billion as of December 31, 2021 and 2020, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

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

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2021 are as follows:

	(In millions)
2022	$	213
2023	123
2024	—
2025	500
2026	212
Thereafter	5,296
Notes and debentures, excluding discounts and debt issuance costs	$	6,344

Uncommitted Lines of Credit

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

Unsecured Committed Bank 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 December 31, 2021. The facility is for general corporate purposes. As of December 31, 2021, there were $542 million of borrowings and an aggregate of £748 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate of £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit 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.

At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the LIBOR, plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon Apache’s senior long-term debt rating. At December 31, 2021, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

The financial covenants of the 2018 credit facility require Apache to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015.

The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.9 billion as of December 31, 2021. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 December 31, 2021, there were $657 million of borrowings and a $2.0 million of 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 agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to ALTM and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00.

The terms of Altus Midstream LP’s Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by ALTM and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 14—Redeemable Noncontrolling Interest — Altus for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners. 

The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA Corporation, Apache or any of APA Corporation’s other subsidiaries.

There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2021.

Commercial Paper Program

As of December 31, 2020, Apache had no commercial paper outstanding. Apache did not use its commercial paper program in 2021 and terminated the program during the third quarter of 2021.

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Financing Costs, Net

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Interest expense	$	419	$	438	$	430
Amortization of debt issuance costs	8		8		7
Capitalized interest	—		(12)		(37)
Loss (gain) on extinguishment of debt	104		(160)		75
Interest income	(8)		(7)		(13)
Interest income from APA Corporation, net	(51)		—		—
Financing costs, net	$	472	$	267	$	462

As of December 31, 2021, the Company had $39 million of debt issuance costs, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $6 million, $7 million, and $2 million was recorded as interest expense in 2021, 2020, and 2019, respectively.

11. INCOME TAXES

Income (loss) before income taxes is composed of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
U.S.	$	689	$	(4,581)	$	(4,397)
Foreign	1,291		(259)		1,389
Total	$	1,980	$	(4,840)	$	(3,008)

The total income tax provision consists of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Current income taxes:
Federal	$	16	$	(2)	$	1
Foreign	636		178		659
	652		176		660
Deferred income taxes:
Federal	—		—		67
Foreign	(74)		(112)		(53)
	(74)		(112)		14
Total	$	578	$	64	$	674

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	416	$	(1,016)	$	(631)
State income tax, less federal effect(1)	—		—		1
Taxes related to foreign operations	300		97		328
Tax credits	(10)		(13)		(6)
Net change in tax contingencies	16		1		1
Goodwill impairment	—		35		—
Valuation allowances(1)	(111)		965		972
Tax attributable to Altus Preferred Unit limited partners	(34)		(16)		(8)
All other, net	1		11		17
	$	578	$	64	$	674

(1)The change in state valuation allowance is included as a component of state income tax.

The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax liability consists of the following as of December 31:

	2021		2020
	(In millions)
Deferred tax assets:
U.S. and state net operating losses	$	2,494	$	2,306
Capital losses	647		633
Tax credits and other tax incentives	24		33
Foreign tax credits	2,241		2,241
Accrued expenses and liabilities	152		93
Asset retirement obligation	712		654
Property and equipment	3		261
Investment in Altus Midstream LP	64		76
Net interest expense limitation	135		252
Lease liability	81		79
Decommissioning contingency for sold Gulf of Mexico properties	263		—
Other	1		1
Total deferred tax assets	6,817		6,629
Valuation allowance	(5,875)		(5,991)
Net deferred tax assets	942		638
Deferred tax liabilities:
Equity investments	2		4
Property and equipment	748		750
Right-of-use asset	77		74
Decommissioning security for sold Gulf of Mexico properties	164		—
Other	86		13
Total deferred tax liabilities	1,077		841
Net deferred income tax liability	$	135	$	203

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:

	2021		2020
	(In millions)
Assets:
Deferred charges and other	$	13	$	12
Liabilities:
Income taxes	148		215
Net deferred income tax liability	$	135	$	203

The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize existing deferred tax assets. A significant piece of negative evidence evaluated was the pre-tax book cumulative loss incurred over the three-year period ended December 31, 2021. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth.

In 2021, 2020, and 2019, the Company’s valuation allowance decreased by $116 million, increased by $1.0 billion, and increased by $1.0 billion, respectively, as detailed in the table below:

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	5,991	$	4,959	$	3,947
State(1)	1		67		41
U.S.	(112)		960		971
Foreign	(5)		5		—
Balance at end of year	$	5,875	$	5,991	$	4,959

(1)Reported as a component of state income taxes.

On December 31, 2021, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
U.S.	$	9,717	2021 - Indefinite
State	6,695		Various
Foreign	1		2028 - Indefinite

The Company has a U.S. net operating loss carryforward of $9.7 billion, which includes $177 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has a net interest expense carryover of $610 million under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.9 billion, which has a five year carryover period expiring in 2023 and a Canadian capital loss carryforward of $836 million which has an indefinite carryover. The Company has recorded a full valuation allowance against the U.S. net operating losses, the state net operating losses, the net interest expense carryover, the U.S. capital loss, and the Canadian capital loss because it is more likely than not that these attributes will not be realized.

On December 31, 2021, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,241	2025-2026

The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a full valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold that a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	93	$	82	$	24
Additions based on tax positions related to prior year	16		—		49
Additions based on tax positions related to the current year	7		11		9
Balance at end of year	$	116	$	93	$	82

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2021, 2020, and 2019, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2021, 2020, and 2019, the Company had an accrued liability for interest and penalties of $4 million, $3 million, and $2 million, respectively.

In 2021, 2020, and 2019, the Company recorded a $23 million net increase, an $11 million net increase, and a $58 million net increase, respectively, in its reserve for uncertain tax positions. The Company is currently under IRS audit for the 2014 through 2017 tax years.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. Apache’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction

U.S.	2014
Egypt	2005
U.K.	2020

12.    COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory control, which also may include controls related to the potential impacts of climate changes. As of December 31, 2021, the Company has an accrued liability of approximately $84 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.

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Argentine Environmental Claims

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration 

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

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

Apollo Exploration Lawsuit

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

Australian Operations Divestiture Dispute

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

F-36

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Canadian Operations Divestiture Dispute

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

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases 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. After removal of this lawsuit to federal court, the district court remanded it back to state court. The remand order is being appealed to the 3rd Circuit Court of Appeals. Further activity in the case has been stayed pending this appellate review.

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

Castex Lawsuit

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

Oklahoma Class Actions

The Company is a party to two purported class actions in Oklahoma styled Bigie Lee Rhea v. Apache Corporation, Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219. The Rhea case has been certified and includes a class of royalty owners seeking damages of approximately $200 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Rhea case under which Apache will pay $25 million to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized in the first quarter of 2022.

F-37

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Shareholder and Derivative Lawsuits

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

On March 16, 2021, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 334th District Court of Harris County, Texas. The case purports to be a derivative action brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe the plaintiff’s claims lack merit and intend to vigorously defend this lawsuit.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.

As of December 31, 2021, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

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

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company is not aware of any environmental claims existing as of December 31, 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 Decommissioning Obligations on Sold Properties

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

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

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

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

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Leases and Contractual Obligations

On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. As allowed under the standard, the Company applied practical expedients permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as permitting an entity the option to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs.

The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, Apache records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, Apache enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable.

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $127 million, $149 million, and $222 million for the full years of 2021, 2020, and 2019, respectively. Apache elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation.

In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million, $2 million, and $7 million in 2021, 2020, and 2019, respectively. Interest on the Company’s finance lease asset was $2 million, $2 million, and $3 million in 2021, 2020, and 2019, respectively.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2021:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		11.7 years
Weighted average discount rate	3.7	%	4.4	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)	Operating Leases(2)		Finance Leases(3)		Purchase Obligations(4)(5)
	(In millions)
2022	$	106	$	3	$	230
2023	75		3		199
2024	58		3		161
2025	7		4		159
2026	7		4		3,637
Thereafter	18		25		463
Total future minimum payments	271		42		$	4,849
Less: imputed interest	(22)		(6)		N/A
Total lease liabilities	249		36		N/A
Current portion	99		2		N/A
Non-current portion	$	150	$	34	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $194 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.

(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $63 million, $41 million and $78 million in 2021, 2020, and 2019, respectively.

13.    RETIREMENT AND DEFERRED COMPENSATION PLANS

The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of eligible employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a qualifying change in control of ownership of APA, immediate and full vesting occurs.

Additionally, Apache North Sea Limited maintains a separate retirement plan, as required under the laws of the U.K.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $31 million, $43 million, and $52 million for 2021, 2020, and 2019, respectively.

The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2021, 2020, and 2019, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	233		$	20		$	199		$	20		$	187		$	27
Service cost	3			1			3			1			3			2
Interest cost	3			—			4			—			5			1
Foreign currency exchange rates	(2)			—			8			—			7			—
Actuarial losses (gains)	(5)			1			30			1			15			(9)
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Projected benefit obligation at end of year	211			20			233			20			199			20
Change in Plan Assets
Fair value of plan assets at beginning of year	262			—			228			—			208			—
Actual return on plan assets	11			—			31			—			25			—
Foreign currency exchange rates	(3)			—			9			—			8			—
Employer contributions	5			2			5			2			5			1
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Fair value of plan assets at end of year	254			—			262			—			228			—
Funded status at end of year	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	43			(18)			29			(18)			29			(18)
	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	1		$	14		$	(11)		$	16		$	(7)		$	19
Weighted Average Assumptions used as of December 31
Discount rate	1.80		%	2.57		%	1.40		%	2.06		%	2.10		%	3.00		%
Salary increases	4.90		%	N/A			4.50		%	N/A			4.30		%	N/A
Expected return on assets	1.90		%	N/A			1.50		%	N/A			2.20		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.00		%	N/A			6.25		%
Ultimate in 2028	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

As of December 31, 2021, 2020, and 2019, the accumulated benefit obligation for the U.K. Pension Plan was $205 million, $207 million, and $181 million, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in a blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:

	Target Allocation		Percentage of Plan Assets at Year-End
	2021		2021		2020
Asset Category
Equity securities:
Overseas quoted equities	15	%	15	%	19	%
Total equity securities	15	%	15	%	19	%
Debt securities:
U.K. government bonds	55	%	54	%	64	%
U.K. corporate bonds	24	%	25	%	16	%
Total debt securities	79	%	79	%	80	%
Cash	6	%	6	%	1	%
Total	100	%	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2021 and 2020 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2021 and 2020:

	December 31,
	2021		2020
	(In millions)
Equity securities:
Overseas quoted equities	$	38	$	49
Total equity securities	38		49
Debt securities:
U.K. government bonds	138		168
U.K. corporate bonds	62		43
Total debt securities	200		211
Cash	16		2
Fair value of plan assets	$	254	$	262

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2021, 2020, and 2019: 

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	3		$	1		$	3		$	1		$	3		$	2
Interest cost	3			—			4			—			5			1
Expected return on assets	(4)			—			(5)			—			(5)			—
Amortization of loss	—			(1)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	2		$	—		$	2		$	—		$	3		$	2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	1.40		%	2.06		%	2.10		%	3.00		%	2.90		%	4.13		%
Salary increases	4.50		%	N/A			4.30		%	N/A			4.70		%	N/A
Expected return on assets	1.50		%	N/A			2.20		%	N/A			2.80		%	N/A
Healthcare cost trend
Initial	N/A			6.00		%	N/A			6.25		%	N/A			6.50		%
Ultimate in 2025	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

Apache expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2022. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2022	$	6	$	2
2023	7		2
2024	6		2
2025	6		2
2026	6		2
Years 2027-2031	39		6

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14.    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 of 1933, as amended (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

•The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

•The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

•The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

•Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

•Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

•Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $57 million as of December 31, 2021. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. Refer to Note 5—Derivative Instruments and Hedging Activities for more detail.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent 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 for the years ended December 31, 2021 and 2020 is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units: at December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions paid to Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream net income	N/A	76
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment	N/A	82
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2021	660,694	712
Preferred Units embedded derivative(2)		57
		$	769

(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of December 31, 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 December 31, 2021, the Redemption Price would have been based on an 11.5 percent internal rate of return, which would equate to a redemption value of $739 million.

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

N/A - not applicable.

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15.    CAPITAL STOCK AND EQUITY

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

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

Net Income (Loss) per Common Share

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

Common Stock Dividend

In the first quarter of 2020, Apache’s board of directors (Board of Directors) approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the year ended December 31, 2021, the Company paid $43 million in capital distributions to its parent, APA, which is included as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

Stock Compensation Plans

Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, including stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting.

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2021, 11.0 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Stock-settled and cash-settled compensation expensed	$	152	$	40	$	110
Stock-settled and cash-settled compensation capitalized	18		7		28
Total stock-settled and cash-settled compensation costs	$	170	$	47	$	138

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Stock Options

As of December 31, 2021, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan and, collectively with the 2016 Plan and the 2011 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

The following table summarizes stock option activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price
	(In thousands, except exercise price amounts)
Outstanding, beginning of year	3,537	$	72.10	4,298	$	75.24	4,872	$	75.95
Forfeited	—	—		(37)	44.98		(80)	34.58
Expired	(525)	119.83		(724)	92.14		(494)	88.82
Outstanding, end of year(1)	3,012	63.79		3,537	72.10		4,298	75.24
Expected to vest	—	—		150	45.77		495	49.11
Exercisable, end of year(2)	3,012	63.79		3,387	73.26		3,803	78.64

(1)As of December 31, 2021, options outstanding had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

(2)As of December 31, 2021, options exercisable had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

There were no options issued and no options exercised during the years ended December 31, 2021, 2020, and 2019.

Restricted Stock Units and Restricted Stock Phantom Units

Prior to consummation of the Holding Company Reorganization, the Company had restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either APA’s common stock or in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

For the years ended December 31, 2021, 2020, and 2019, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $91 million, $39 million, and $104 million, respectively. As of December 31, 2021, 2020, and 2019, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $15 million, $6 million, and $24 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value
	(In thousands, except per share amounts)
Non-vested, beginning of year	1,552	$	28.43	2,448	$	46.65	3,153	$	55.54
Granted	1,506	16.46		1,352	24.60		1,479	36.81
Vested(3)	(857)	29.13		(1,933)	48.65		(1,899)	53.99
Forfeited	(128)	19.78		(315)	30.09		(285)	45.06
Non-vested, end of year(1)(2)	2,073	19.98		1,552	28.43		2,448	46.65

(1)As of December 31, 2021, there was $14 million of total unrecognized compensation cost related to 2,073,419 unvested stock-settled restricted stock units.

(2)As of December 31, 2021, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2021, 2020, and 2019 were approximately $25 million, $94 million, and $103 million, respectively.

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2021, 2020, and 2019:

	For the Year Ended December 31,
	2021	2020	2019
	(In thousands)
Non-vested, beginning of year	4,423	5,384	1,818
Adjustment for ALTM reverse stock split(1)	—	(1,246)	—
Granted(2)	4,441	3,462	4,831
Vested	(2,049)	(1,618)	(616)
Forfeited	(413)	(1,559)	(649)
Non-vested, end of year(3)	6,402	4,423	5,384

(1)On June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock.

(2)Restricted stock phantom units granted during 2021 and 2020 included 4,375,546 and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 65,327 and 83,239 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2021 was approximately $74 million.

In January 2022, APA awarded 775,942 restricted stock units and 2,512,602 restricted stock phantom units based on APA’s weighted-average per-share market price of $29.46 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $23 million and $76 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of APA’s common stock.

Also during January 2022, APA awarded 27,643 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $63.63. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $2 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of ALTM’s common stock.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2021, are as described below:

•In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 1,868 restricted stock units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 54 percent of target.

•In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 97,645 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 23 percent of target.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

•In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 1,247,706 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 100 percent of target.

•In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,330,823 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 2,661,646 phantom units could be awarded.

•In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,854,736 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 3,709,472 units could be awarded.

The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the performance programs were an expense of $56 million, a credit of $8 million, and an expense of $24 million during 2021, 2020, and 2019, respectively. Capitalized compensation costs under the performance programs were an expense of $3 million, a credit of $1 million, and an expense of $3 million during 2021, 2020, and 2019, respectively.

The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2021:

	Units
	(In thousands)
Non-vested, beginning of year	3,417
Granted	1,782
Vested	(76)
Forfeited	(240)
Expired	(352)
Non-vested, end of year(1)	4,531

(1)As of December 31, 2021, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $36 million.

In January 2022, APA’s board of directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Payout for 50 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 2,186,068 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $41.88 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $29.46 based on the weighted-average fair market value of a share of common stock of APA as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Components of accumulated other comprehensive income (loss) include the following:

	As of December 31,
	2021		2020		2019
	(In millions)
Share of equity method interests other comprehensive loss	$	—	$	(1)	$	(1)
Pension and postretirement benefit plan (Note 13)	22		15		17
Accumulated other comprehensive income	$	22	$	14	$	16

17.    MAJOR CUSTOMERS

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP PLC and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.

Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18.    BUSINESS SEGMENT INFORMATION

As of December 31, 2021, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces natural gas, crude oil, and NGLs. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration	63		34		28		—		2		127
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(128)		5,097
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(2)	2,888
Other Income (Expense):
Gain on divestitures, net											67
Loss on previously sold Gulf of Mexico properties											(446)
Derivative instrument gain, net											94
Other											228
General and administrative											(357)
Transaction, reorganization, and separation											(22)
Financing costs, net											(472)
Income Before Income Taxes											$	1,980
Total Assets(3)	$	2,796	$	2,199	$	7,700	$	1,698	$	—	$	14,393
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	—	$	8,060
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	—	$	1,004

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2020
Oil revenues	$	1,102	$	795	$	1,209	$	—	$	—	$	3,106
Natural gas revenues	280		67		251		—		—		598
Natural gas liquids revenues	8		21		304		—		—		333
Oil, natural gas, and natural gas liquids production revenues	1,390		883		1,764		—		—		4,037
Purchased oil and gas sales	—		—		394		4		—		398
Midstream service affiliate revenues	—		—		—		145		(145)		—
	1,390		883		2,158		149		(145)		4,435
Operating Expenses:
Lease operating expenses	424		305		400		—		(2)		1,127
Gathering, processing, and transmission	38		50		291		38		(143)		274
Purchased oil and gas costs	—		—		354		3		—		357
Taxes other than income	—		—		108		15		—		123
Exploration	63		28		168		—		15		274
Depreciation, depletion, and amortization	601		380		779		12		—		1,772
Asset retirement obligation accretion	—		73		32		4		—		109
Impairments	529		7		3,963		2		—		4,501
	1,655		843		6,095		74		(130)		8,537
Operating Income (Loss)	$	(265)	$	40	$	(3,937)	$	75	$	(15)	(4,102)
Other Income (Expense):
Gain on divestitures, net											32
Derivative instrument losses, net											(223)
Other											64
General and administrative											(290)
Transaction, reorganization, and separation											(54)
Financing costs, net											(267)
Loss Before Income Taxes											$	(4,840)
Total Assets(3)	$	3,003	$	2,220	$	5,540	$	1,786	$	197	$	12,746
Net Property and Equipment	$	1,955	$	1,773	$	4,760	$	196	$	135	$	8,819
Additions to Net Property and Equipment	$	454	$	215	$	345	$	12	$	136	$	1,162

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2019
Oil revenues	$	1,969	$	1,163	$	2,098	$	—	$	—	$	5,230
Natural gas revenues	295		90		293		—		—		678
Natural gas liquids revenues	12		23		372		—		—		407
Oil, natural gas, and natural gas liquids production revenues	2,276		1,276		2,763		—		—		6,315
Purchased oil and gas sales	—		—		176		—		—		176
Midstream service affiliate revenues	—		—		—		136		(136)		—
	2,276		1,276		2,939		136		(136)		6,491
Operating Expenses:
Lease operating expenses	484		320		645		—		(2)		1,447
Gathering, processing, and transmission	40		45		299		56		(134)		306
Purchased oil and gas costs	—		—		142		—		—		142
Taxes other than income	—		—		194		13		—		207
Exploration	100		2		688		—		15		805
Depreciation, depletion, and amortization	708		366		1,566		40		—		2,680
Asset retirement obligation accretion	—		76		29		2		—		107
Impairments	—		—		1,648		1,301		—		2,949
	1,332		809		5,211		1,412		(121)		8,643
Operating Income (Loss)	$	944	$	467	$	(2,272)	$	(1,276)	$	(15)	(2,152)
Other Income (Expense):
Gain on divestitures, net											43
Derivative instrument losses, net											(35)
Other											54
General and administrative											(406)
Transaction, reorganization, and separation											(50)
Financing costs, net											(462)
Loss Before Income Taxes											$	(3,008)
Total Assets(3)	$	3,700	$	2,473	$	10,388	$	1,479	$	67	$	18,107
Net Property and Equipment	$	2,573	$	1,956	$	9,385	$	206	$	38	$	14,158
Additions to Net Property and Equipment	$	454	$	183	$	1,696	$	308	$	93	$	2,734

(1)Includes revenue from non-customers for the years ended December 31, 2021, 2020, and 2019 of:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil	$	420	$	95	$	410
Natural gas	47		14		40
Natural gas liquids	2		—		1

(2)Includes a noncontrolling interest in Egypt and Altus Midstream.

(3)Intercompany balances are excluded from total assets.

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

19.    SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions, except per boe)
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		2		127
Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		2		4,278
Results of operations	$	1,440	$	585	$	200	$	(2)	$	2,223
2020
Oil and gas production revenues	$	1,764	$	1,390	$	883	$	—	$	4,037
Operating cost:
Depreciation, depletion, and amortization(2)	726		540		377		—		1,643
Asset retirement obligation accretion	32		—		73		—		105
Lease operating expenses	400		424		305		—		1,129
Gathering, processing, and transmission	291		38		50		—		379
Exploration expenses	168		63		28		15		274
Impairments related to oil and gas properties	3,938		374		7		—		4,319
Production taxes(3)	106		—		—		—		106
Income tax	(818)		(22)		17		—		(823)
	4,843		1,417		857		15		7,132
Results of operations	$	(3,079)	$	(27)	$	26	$	(15)	$	(3,095)
2019
Oil and gas production revenues	$	2,763	$	2,276	$	1,276	$	—	$	6,315
Operating cost:
Depreciation, depletion, and amortization(2)	1,508		641		363		—		2,512
Asset retirement obligation accretion	29		—		76		—		105
Lease operating expenses	645		484		320		—		1,449
Gathering, processing, and transmission	299		40		45		—		384
Exploration expenses	688		100		2		15		805
Impairments related to oil and gas properties	1,633		—		—		—		1,633
Production taxes(3)	191		—		—		—		191
Income tax	(468)		455		188		—		175
	4,525		1,720		994		15		7,254
Results of operations	$	(1,762)	$	556	$	282	$	(15)	$	(939)

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 18—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 18—Business Segment Information.

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities

	United States		Egypt(2)		North Sea		Other International		Total(2)
	(In millions)
2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		30		161
Development	545		404		135		1		1,085
Costs incurred(1)	$	560	$	353	$	174	$	31	$	1,118
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	—	$	—
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts - Proved and Unproved	—		(145)		—		—		(145)
2020
Acquisitions:
Proved	$	—	$	7	$	—	$	—	$	7
Unproved	4		—		—		—		4
Exploration	8		102		68		150		328
Development	332		378		162		—		872
Costs incurred(1)	$	344	$	487	$	230	$	150	$	1,211
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—	$	—	$	—	$	3	$	3
Asset retirement costs	9		—		29		—		38
2019
Acquisitions:
Proved	$	3	$	5	$	—	$	—	$	8
Unproved	47		10		—		—		57
Exploration	162		139		62		105		468
Development	1,500		374		119		3		1,996
Costs incurred(1)	$	1,712	$	528	$	181	$	108	$	2,529
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	23	$	—	$	5	$	4	$	32
Asset retirement costs	14		—		(111)		—		(97)
(2) Includes a noncontrolling interest in Egypt.

 In 2021, in connection with Apache’s agreement to enter into a modernized PSC agreement with EGPC, as referenced in Note 1—Summary of Significant Accounting Policies, the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments.

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions)
2021
Proved properties	$	18,732	$	12,373	$	8,954	$	—	$	40,059
Unproved properties	319		63		33		—		415
	19,051		12,436		8,987		—		40,474
Accumulated DD&A	(14,814)		(10,767)		(7,345)		—		(32,926)
	$	4,237	$	1,669	$	1,642	$	—	$	7,548
2020
Proved properties	$	20,343	$	12,069	$	8,805	$	—	$	41,217
Unproved properties	348		77		42		135		602
	20,691		12,146		8,847		135		41,819
Accumulated DD&A	(16,252)		(10,290)		(7,081)		—		(33,623)
	$	4,439	$	1,856	$	1,766	$	135	$	8,196

(1)Includes a noncontrolling interest in Egypt..

Oil and Gas Reserve Information

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	300,484	110,014	104,491	514,989
December 31, 2019	278,145	103,573	101,712	483,430
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
Proved undeveloped reserves:
December 31, 2018	45,182	9,484	11,278	65,944
December 31, 2019	46,716	10,831	10,049	67,596
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
Total proved reserves:
Balance December 31, 2018	345,666	119,498	115,769	580,933
Extensions, discoveries and other additions	52,297	21,039	9,017	82,353
Revisions of previous estimates	(16,446)	4,752	5,132	(6,562)
Production	(38,344)	(30,885)	(18,157)	(87,386)
Sales of minerals in-place	(18,312)	—	—	(18,312)
Balance December 31, 2019	324,861	114,404	111,761	551,026
Extensions, discoveries and other additions	17,858	17,855	5,275	40,988
Revisions of previous estimates	(69,247)	2,541	(4,756)	(71,462)
Production	(32,299)	(27,591)	(18,441)	(78,331)
Sales of minerals in-place	(8,721)	—	—	(8,721)
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615

(1)Includes proved reserves of 39 MMbbls, 36 MMbbls, 38 MMbbls, and 40 MMbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	197,574	502	1,938	200,014
December 31, 2019	158,794	667	2,317	161,778
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
Proved undeveloped reserves:
December 31, 2018	33,796	60	631	34,487
December 31, 2019	23,569	90	660	24,319
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
Total proved reserves:
Balance December 31, 2018	231,370	562	2,569	234,501
Extensions, discoveries and other additions	41,343	27	697	42,067
Revisions of previous estimates	(32,569)	508	345	(31,716)
Production	(24,959)	(340)	(634)	(25,933)
Sales of minerals in-place	(32,822)	—	—	(32,822)
Balance December 31, 2019	182,363	757	2,977	186,097
Extensions, discoveries and other additions	11,435	97	312	11,844
Revisions of previous estimates	(469)	264	(207)	(412)
Production	(27,133)	(276)	(709)	(28,118)
Sales of minerals in-place	(456)	—	—	(456)
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362

(1)  Includes proved reserves of 159 Mbbls, 281 Mbbls, 252 Mbbls, and 187 Mbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)
	(Millions of cubic feet)
Proved developed reserves:
December 31, 2018	1,626,403	476,132	95,347	2,197,882
December 31, 2019	945,938	433,382	106,329	1,485,649
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
Proved undeveloped reserves:
December 31, 2018	267,090	33,006	15,804	315,900
December 31, 2019	115,040	24,704	16,604	156,348
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
Total proved reserves:
Balance December 31, 2018	1,893,493	509,138	111,151	2,513,782
Extensions, discoveries and other additions	249,205	34,758	27,711	311,674
Revisions of previous estimates	(509,753)	18,570	4,015	(487,168)
Production	(233,447)	(104,380)	(19,944)	(357,771)
Sales of minerals in-place	(338,520)	—	—	(338,520)
Balance December 31, 2019	1,060,978	458,086	122,933	1,641,997
Extensions, discoveries and other additions	60,965	83,718	8,140	152,823
Revisions of previous estimates	215,166	(19,849)	(33,541)	161,776
Production	(205,594)	(100,348)	(21,032)	(326,974)
Sales of minerals in-place	(2,255)	—	—	(2,255)
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906

(1) Includes proved reserves of 158 Bcf, 141 Bcf, 153 Bcf, and 170 Bcf as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2018	769,125	189,871	122,320	1,081,316
December 31, 2019	594,595	176,470	121,751	892,816
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
Proved undeveloped reserves:
December 31, 2018	123,493	15,045	14,543	153,081
December 31, 2019	89,458	15,038	13,476	117,972
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
Total proved reserves:
Balance December 31, 2018	892,618	204,916	136,863	1,234,397
Extensions, discoveries and other additions	135,174	26,859	14,333	176,366
Revisions of previous estimates	(133,974)	8,355	6,146	(119,473)
Production	(102,211)	(48,622)	(22,115)	(172,948)
Sales of minerals in-place	(107,554)	—	—	(107,554)
Balance December 31, 2019	684,053	191,508	135,227	1,010,788
Extensions, discoveries and other additions	39,454	31,905	6,944	78,303
Revisions of previous estimates	(33,854)	(502)	(10,554)	(44,910)
Production	(93,698)	(44,592)	(22,655)	(160,945)
Sales of minerals in-place	(9,553)	—	—	(9,553)
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962

(1) Includes total proved reserves of 66 MMboe, 59 MMboe, 64 MMboe, and 68 MMboe as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.

As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2020, the Company added approximately 78 MMboe from extensions, discoveries, and other additions. The Company recorded 39 MMboe of exploration and development adds in the U.S., primarily in the Southern Midland Basin (26 MMboe) associated with the Wolfcamp and Spraberry drilling programs and the remainder in the Delaware Basin and Austin Chalk. The international operations contributed 39 MMboe of exploration and development adds during 2020, with Egypt contributing 32 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and Umbarka Area concessions. The North Sea contributed 7 MMboe from drilling success, primarily in the Beryl Field. The Company had combined downward revisions of previously estimated reserves of 45 MMboe. Downward revisions related to changes in product prices accounted for 70 MMboe, engineering and performance upward revisions accounted for 27 MMboe, and downward interest revisions accounted for 2 MMboe. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge.

During 2019, the Company added approximately 176 MMboe from extensions, discoveries, and other additions. The Company recorded 135 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Spraberry, Barnett, and Wolfcamp drilling programs in the Permian Basin (129 MMboe) and various offset drilling activity in the Midcontinent region (6 MMboe). The Company’s international assets contributed 41 MMboe of exploration and development adds during 2019. Egypt contributed 27 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, East Bahariya Extension 3, and West Kanayis concessions. The North Sea contributed 14 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 119 MMboe. Downward revisions related to changes in product prices accounted for 139 MMboe and engineering and performance upward revisions accounted for 20 MMboe. The Company also sold 107 MMboe of proved reserves associated with U.S. divestitures, primarily related to the sale of the Company’s Woodford-SCOOP and STACK plays and Western Anadarko Basin assets.

Approximately 12 percent of the Company’s year-end 2021 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.”

F-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Future Net Cash Flows

Future cash inflows as of December 31, 2021, 2020, and 2019 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

	United States		Egypt(1)		North Sea		Total(1)
	(In millions)
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360
2020
Cash inflows	$	12,537	$	5,560	$	4,122	$	22,219
Production costs	(6,244)		(1,704)		(2,388)		(10,336)
Development costs	(1,555)		(633)		(2,448)		(4,636)
Income tax expense	—		(1,096)		316		(780)
Net cash flows	4,738		2,127		(398)		6,467
10 percent discount rate	(1,829)		(437)		1,111		(1,155)
Discounted future net cash flows(2)	$	2,909	$	1,690	$	713	$	5,312
2019
Cash inflows	$	21,694	$	8,306	$	7,454	$	37,454
Production costs	(10,642)		(1,847)		(2,730)		(15,219)
Development costs	(1,740)		(707)		(2,651)		(5,098)
Income tax expense	(27)		(1,930)		(784)		(2,741)
Net cash flows	9,285		3,822		1,289		14,396
10 percent discount rate	(4,003)		(808)		297		(4,514)
Discounted future net cash flows(2)	$	5,282	$	3,014	$	1,586	$	9,882

(1)Includes discounted future net cash flows of approximately $1.1 billion, $563 million, and $1.0 billion as of December 31, 2021, 2020, and 2019, respectively, attributable to a noncontrolling interest in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $15.3 billion, $7.1 billion, and $12.4 billion as of December 31, 2021, 2020, and 2019, respectively.

F-65

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table sets forth the principal sources of change in the discounted future net cash flows:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Sales, net of production costs	$	(4,707)	$	(2,422)	$	(4,291)
Net change in prices and production costs	9,376		(5,753)		(3,034)
Discoveries and improved recovery, net of related costs	1,749		751		2,042
Change in future development costs	(839)		20		(75)
Previously estimated development costs incurred during the period	545		576		983
Revision of quantities	1,983		(418)		(741)
Purchases of minerals in-place	1		—		—
Accretion of discount	626		1,236		1,693
Change in income taxes	(1,583)		1,533		720
Sales of minerals in-place	(116)		(104)		(817)
Change in production rates and other	13		11		(319)
	$	7,048	$	(4,570)	$	(3,839)

F-66

EX-23.1

TBPE REGISTERED ENGINEERING FIRM F-1580FAX (713) 651-0849

1100 LOUISIANA SUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191

EXHIBIT 23.1

Consent of Ryder Scott Company, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Corporation to our Firm's name and our Firm's review of the proved oil and gas reserve quantities of Apache Corporation as of December 31, 2021, and to the inclusion of our report, dated January 21, 2022, as an exhibit to this Form 10-K filed with the Securities and Exchange Commission.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

                            TBPELS Firm Registration No. F-1580

Houston, Texas

February 22, 2022

SUITE 2800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    

633 17TH STREET, SUITE 1700         DENVER, COLORADO 80202    TEL (303) 339-8110    

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

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

Date: February 22, 2022

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

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

Date: February 22, 2022

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the Annual Report on Form 10-K of Apache Corporation for the period ending December 31, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

Date: February 22, 2022

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

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the Annual Report on Form 10-K of Apache Corporation for the period ending December 31, 2021, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

Date: February 22, 2022

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

EX-99.1

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS APACHE CORPORATION Estimated Future Reserves Attributable to Certain Leasehold and Royalty Interests and Derived Through Certain Production Sharing Contracts SEC Parameters As of December 31, 2021 /s/ Ali A. Porbandarwala Ali A. Porbandarwala, P.E. TBPELS License No. 107652 Senior Vice President [SEAL] RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580

SUITE 2800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 633 17TH STREET, SUITE 1700 DENVER, COLORADO 80202 TEL (303) 339-8110 TBPELS REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849 1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191 January 21, 2022 Apache Corporation 2000 Post Oak Boulevard, Suite 100 Houston, Texas 77056-4400 Ladies and Gentlemen: At the request of Apache Corporation (Apache), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2021 prepared by Apache’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 17, 2022 and presented herein, was prepared for public disclosure by Apache in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Apache’s estimated net reserves attributable to the leasehold and royalty interests and derived through certain production sharing contracts in certain properties owned by Apache and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2021. The properties reviewed by Ryder Scott incorporate Apache’s reserves determinations and are attributable to the interests of Apache Corporation (U.S.A), Apache Egypt Companies (Egypt), and Apache North Sea Limited (United Kingdom). The properties reviewed by Ryder Scott account for a portion of Apache’s total net proved reserves as of December 31, 2021. Based on the estimates of total net proved reserves prepared by Apache, the reserves audit conducted by Ryder Scott addresses 82.4 percent of the total proved developed net liquid hydrocarbon reserves, 78.9 percent of the total proved developed net gas reserves, 70.9 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 72.9 percent of the total proved undeveloped net gas reserves of Apache. The wells or locations for which estimates of reserves were reviewed by Ryder Scott were selected by Apache. Apache informed Ryder Scott that the selected reserves for each country included at least 81.5 percent or more of the total proved discounted future net income at 10 percent attributable to the respective country’s total interests of Apache (coverage) based on SEC hydrocarbon price parameters as of December 31, 2021. Total coverage of world-wide reserves is 83.3 percent of the total proved discounted future net income at 10 percent. As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or

Apache Corporation – Total All Regions January 21, 2022 Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties. Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2021 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. The estimated reserves presented in this report are related to hydrocarbon prices. Apache has informed us that in the preparation of their reserves and income projections, as of December 31, 2021, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Apache attributable to Apache's interest and entitlement in properties that we reviewed and the reserves of properties that we did not review are summarized below: SEC PARAMETERS Estimated Net Proved Reserves Certain Leasehold and Royalty Interests and Derived Through Certain Production Sharing Contracts of Apache Corporation (Total All Countries) As of December 31, 2021 % Crude Oil & Condensate Reserves Reviewed % Natural Gas Liquids Reserves Reviewed % Gas Reserves Reviewed Reviewed by Ryder Scott Not Reviewed Total Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMCF Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMCF Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMCF Developed 84.0 79.0 78.9 306,303 131,642 1,402,696 58,383 35,038 375,725 364,686 166,680 1,778,421 Undeveloped 67.6 77.9 72.9 23,602 12,999 146,924 11,326 3,686 54,551 34,928 16,685 201,475 Total Proved 82.6 78.9 78.3 329,905 144,641 1,549,620 69,709 38,724 430,276 399,614 183,365 1,979,896

Apache Corporation – Total All Regions January 21, 2022 Page 3 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS SEC PARAMETERS Estimated Net Proved Reserves Certain Leasehold and Royalty Interests and Derived Through Certain Production Sharing Contracts of Apache Corporation (Summary by Country) As of December 31, 2021 % Crude Oil & Condensate Reserves Reviewed % Natural Gas Liquids Reserves Reviewed % Gas Reserves Reviewed Reviewed by Ryder Scott Not Reviewed Total Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMcf Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMcf Crude Oil & Condensate MBarrels Natural Gas Liquids MBarrels Sales Gas MMcf USA Developed 85.3 79.0 77.8 154,308 129,754 963,089 26,660 34,419 274,372 180,968 164,173 1,237,461 Undeveloped 75.4 77.6 74.7 13,697 12,719 137,858 4,471 3,661 46,583 18,168 16,380 184,441 Total Proved 84.4 78.9 77.4 168,005 142,473 1,100,947 31,131 38,080 320,955 199,136 180,553 1,421,902 Egypt Developed 82.3 87.9 82.2 87,758 393 381,841 18,887 54 82,965 106,645 447 464,806 Undeveloped 57.1 16.7 19.6 6,282 5 1,942 4,721 25 7,968 11,003 30 9,910 Total Proved 79.9 83.4 80.8 94,040 398 383,783 23,608 79 90,933 117,648 477 474,716 United Kingdom Developed 83.3 72.6 75.9 64,237 1,495 57,766 12,836 565 18,388 77,073 2,060 76,154 Undeveloped 62.9 100.0 100.0 3,623 275 7,124 2,134 0 0 5,757 275 7,124 Total Proved 81.9 75.8 77.9 67,860 1,770 64,890 14,970 565 18,388 82,830 2,335 83,278 Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousand of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. Reserves Included in This Report In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report. The various proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed reserves included herein consist of the producing, shut-in and behind pipe status categories. Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Apache’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Apache Corporation – Total All Regions January 21, 2022 Page 4 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered. Audit Data, Methodology, Procedure and Assumptions The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of

Apache Corporation – Total All Regions January 21, 2022 Page 5 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved reserves, prepared by Apache, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November 2021, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Apache or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate. Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method or analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Apache for our review or which we have obtained from public data sources that were available through November 2021. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof. To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review. As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Apache relating to hydrocarbon prices and costs as noted herein. The hydrocarbon prices furnished by Apache for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of- the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Apache Corporation – Total All Regions January 21, 2022 Page 6 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS The initial SEC hydrocarbon prices in effect on December 31, 2021 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices, provided by Apache, appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Apache for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used. The product prices which were actually used by Apache to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache. The table below summarizes Apache’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Apache’s “average realized prices.” The average realized prices shown in the table below were determined from Apache’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Apache’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the following table is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us. Geographic Area Product Price Reference Average Benchmark Prices Average Realized Prices United States Oil/Condensate WTI Cushing $66.56/Bbl $65.67/Bbl NGLs Mt. Belvieu Non-Tet Propane $44.06/Bbl $28.83/Bbl Gas Henry Hub $3.61/MMBTU $3.20/Mcf Egypt Oil/Condensate Brent $69.23/Bbl $68.01/Bbl NGLs Brent $69.23/Bbl $49.91/Bbl Gas Contracts Contract $2.82/Mcf United Kingdom Oil/Condensate Brent $69.23/Bbl $68.78/Bbl NGLs Brent $69.23/Bbl $40.95/Bbl Gas UK National Balancing Point (NBP) $14.02/MMBTU $12.53/Mcf The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Apache’s individual property evaluations. Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Apache Corporation – Total All Regions January 21, 2022 Page 7 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Operating costs furnished by Apache are based on the operating expense reports of Apache and include only those costs directly applicable to the leases, contract areas, or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases, contract areas, and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases, contract areas, and wells under terms of operating agreements. Other costs include transportation and/or processing fees as deductions. The operating costs furnished by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. Development costs furnished by Apache are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache. The estimated net cost of abandonment after salvage was included by Apache for properties where abandonment costs net of salvage were material. Apache’s estimates of the net abandonment costs were accepted without independent verification. The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2021. The implementation of Apache’s development plans as presented to us is subject to the approval process adopted by Apache’s management. As the result of our inquiries during the course of our review, Apache has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Apache’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Apache. Apache has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Apache has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Current costs used by Apache were held constant throughout the life of the properties. Apache’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used by Apache to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Apache’s estimates due to unforeseen factors causing a change in the timing to initiate production.

Apache Corporation – Total All Regions January 21, 2022 Page 8 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. The proved reserves for the properties located in Egypt are subject to the contractual fiscal terms contained in production sharing contracts. For these properties, Ryder Scott audited the gross economic inputs used by Apache in the economic models for Egypt through a comparison of Apache and Ryder Scott’s gross economic volumes. Apache’s gross economic volumes were then used as input to the economic models to generate the net interests used to determine the net reserves summarized in this report. Ryder Scott reviewed the fiscal terms of such contracts and discussed with Apache the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Apache’s representations regarding such contractual information should be construed as a legal opinion on this matter. Ryder Scott did not evaluate the country and geopolitical risks in the countries where Apache operates or has interests. Apache’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the quantities as estimated by Apache. The estimates of proved reserves presented herein were based upon a review of the properties in which Apache owns and derives an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Apache for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Certain technical personnel of Apache are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit. Apache has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Apache’s forecast of future proved production, we have relied upon data

Apache Corporation – Total All Regions January 21, 2022 Page 9 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS furnished by Apache with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Apache. We consider the factual data furnished to us by Apache to be appropriate and sufficient for the purpose of our review of Apache’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Apache and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein. Audit Opinion Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2021 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Apache in their estimate of proved reserves to be effective and in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties. We were in reasonable agreement with Apache's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Apache’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Apache when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned or derived by Apache. Other Properties Other properties, as used herein, are those properties of Apache which we did not review. The proved net reserves attributable to the other properties account for 17.6 percent of the total proved developed net liquid hydrocarbon reserves, 21.1 percent of the total proved developed net gas reserves, 29.1 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 27.1 percent of the total proved undeveloped net gas reserves based on estimates prepared by Apache as of December 31, 2021. The other properties represent 16.7 percent of the total proved discounted future net income at 10 percent based on the unescalated pricing policy of the SEC as taken from reserves and income projections prepared by Apache as of December 31, 2021. The same technical personnel of Apache were responsible for the preparation of the reserves estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have

Apache Corporation – Total All Regions January 21, 2022 Page 10 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above. We are independent petroleum engineers with respect to Apache. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Apache Corporation. Apache makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Apache has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3, Form S-4, and Form S-8 of Apache, of the references to our name, as well as to the references to our third party report for Apache, which appears in the December 31, 2021 annual report on Form 10-K of Apache. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Apache. We have provided Apache with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Apache and the original signed report letter, the original signed report letter shall control and supersede the digital version.

Apache Corporation – Total All Regions January 21, 2022 Page 11 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580 /s/ Ali A. Porbandarwala Ali A. Porbandarwala, P.E. TBPELS License No. 107652 Senior Vice President [SEAL] AAP (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Professional Qualifications of Primary Technical Person The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Ali A. Porbandarwala was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein. Mr. Porbandarwala, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2008, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Porbandarwala served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Porbandarwala’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Employees. Mr. Porbandarwala earned a Bachelor of Science degree in Chemical Engineering from The University of Kansas in 2001 and a Masters in Business Administration from The University of Texas at Austin in 2007 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers. Mr. Porbandarwala also served as the Chairman of the annual Ryder Scott Reserves Conference in Houston, completing its seventeenth year in the industry. In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Porbandarwala fulfills. As part of his 2021 continuing education hours, Mr. Porbandarwala attended 20 hours of formalized training including the 2021 Virtual Ryder Scott Reserves Conference and various other professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Based on his educational background, professional training and more than 13 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Porbandarwala has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein). Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

PETROLEUM RESERVES DEFINITIONS Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. Reserves do not include quantities of petroleum being held in inventory. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

PETROLEUM RESERVES DEFINITIONS Page 3 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and 2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA) EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES Page 2 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals that are open at the time of the estimate but which have not yet started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

XML

Cover - USD ($)	12 Months Ended
	Dec. 31, 2021	Jan. 31, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4300
Entity Registrant Name	APACHE CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0747868
Entity Address, Address Line One	One Post Oak Central, 2000 Post Oak Boulevard, Suite 100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-4400
City Area Code	713
Local Phone Number	296-6000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		1,000
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0000006769
Entity Public Float			$ 0

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas
Auditor Firm ID	42

XML

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
REVENUES AND OTHER:
Derivative instrument gains (losses), net	$ 94	$ (223)	$ (35)
Gain on divestitures, net	67	32	43
Loss on previously sold Gulf of Mexico properties	(446)	0	0
Other, net	228	64	54
Total revenues and other	7,928	4,308	6,553
OPERATING EXPENSES:
Lease operating expenses	1,241	1,127	1,447
Taxes other than income	204	123	207
Exploration	127	274	805
General and administrative	357	290	406
Transaction, reorganization, and separation	22	54	50
Depreciation, depletion, and amortization	1,360	1,772	2,680
Asset retirement obligation accretion	113	109	107
Impairments	208	4,501	2,949
Financing costs, net	472	267	462
Total operating expenses	5,948	9,148	9,561
NET INCOME (LOSS) BEFORE INCOME TAXES	1,980	(4,840)	(3,008)
Current income tax provision	652	176	660
Deferred income tax provision (benefit)	(74)	(112)	14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	1,402	(4,904)	(3,682)
Net income attributable to Altus Preferred Unit limited partners	162	76	38
NET INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	1,062	(4,860)	(3,553)
Noncontrolling Interest, Egypt
OPERATING EXPENSES:
Net income (loss) attributable to nonredeemable noncontrolling interest	174	(121)	167
Noncontrolling Interest, Altus
OPERATING EXPENSES:
Net income (loss) attributable to nonredeemable noncontrolling interest	4	1	(334)
Oil and gas, excluding purchased
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	6,498	4,037	6,315
OPERATING EXPENSES:
Cost of oil and gas purchased	264	274	306
Oil and gas, purchased
REVENUES AND OTHER:
Oil and gas production revenues	1,487	398	176
OPERATING EXPENSES:
Cost of oil and gas purchased	1,580	357	142
Oil and gas
REVENUES AND OTHER:
Total revenues	$ 7,985	$ 4,435	$ 6,491

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net income (loss) including noncontrolling interests	$ 1,402	$ (4,904)	$ (3,682)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	7	(2)	13
Share of equity method interests other comprehensive income (loss)	1	0	(1)
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	1,410	(4,906)	(3,670)
Comprehensive income attributable to Altus Preferred Unit limited partners	162	76	38
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO APA CORPORATION	1,070	(4,862)	(3,541)
Noncontrolling Interest, Egypt
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss), net of tax, attributable to nonredeemable noncontrolling interest	174	(121)	167
Noncontrolling Interest, Altus
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Comprehensive income (loss), net of tax, attributable to nonredeemable noncontrolling interest	$ 4	$ 1	$ (334)

XML

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$ 1,402	$ (4,904)	$ (3,682)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized derivative instrument losses (gains), net	(69)	87	44
Gain on divestitures, net	(67)	(32)	(43)
Exploratory dry hole expense and unproved leasehold impairments	86	211	676
Depreciation, depletion, and amortization	1,360	1,772	2,680
Asset retirement obligation accretion	113	109	107
Impairments	208	4,501	2,949
Provision for (benefit from) deferred income taxes	(74)	(112)	14
Loss (gain) from extinguishment of debt	104	(160)	75
Loss on previously sold Gulf of Mexico properties	446	0	0
Other	(23)	102	50
Changes in operating assets and liabilities:
Receivables	(393)	149	133
Inventories	(9)	19	(41)
Drilling advances and other current assets	60	(29)	30
Deferred charges and other long-term assets	(42)	(13)	0
Accounts payable	205	(167)	(5)
Accounts payable to APA Corporation	40	0	0
Accrued expenses	127	(163)	(84)
Deferred credits and noncurrent liabilities	31	18	(36)
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,505	1,388	2,867
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(934)	(1,270)	(2,594)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(3)	(28)	(327)
Leasehold and property acquisitions	(9)	(4)	(40)
Contributions to Altus equity method interests	(28)	(327)	(501)
Acquisition of Altus equity method interests	0	0	(671)
Proceeds from asset divestitures	256	166	718
Other	52	(3)	(31)
NET CASH USED IN INVESTING ACTIVITIES	(666)	(1,466)	(3,446)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	392	150	0
Proceeds from Altus credit facility	33	228	396
Proceeds from note payable to APA Corporation, net	78	0	0
Fixed rate debt borrowings	0	1,238	989
Payments on fixed-rate debt	(1,795)	(1,243)	(1,150)
Distributions to noncontrolling interest - Egypt	(279)	(91)	(305)
Distributions to Altus Preferred Unit limited partners	(46)	(23)	0
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	0	0	611
Distributions to APA Corporation	(1,182)	0	0
Dividends paid	(9)	(123)	(376)
Treasury stock activity, net	0	1	2
Other	(14)	(44)	(55)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(2,822)	93	112
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	17	15	(467)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	262	247	714
CASH AND CASH EQUIVALENTS AT END OF PERIOD	279	262	247
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	442	419	394
Income taxes paid, net of refunds	$ 633	$ 212	$ 649

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CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
CURRENT ASSETS:
Cash and cash equivalents ($132 and $24 related to Altus VIE)	$ 279	$ 262
Receivables, net of allowance of $109 and $95	1,390	908
Other current assets (Note 6) ($9 and $5 related to Altus VIE)	649	676
Accounts receivable from APA Corporation	77	0
Total current assets	2,395	1,846
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:	40,474	41,819
Gathering, processing, and transmission facilities ($209 and $206 related to Altus VIE)	673	670
Other ($3 and $3 related to Altus VIE)	1,126	1,140
Less: Accumulated depreciation, depletion, and amortization ($25 and $13 related to Altus VIE)	(34,213)	(34,810)
Property and equipment, net	8,060	8,819
OTHER ASSETS:
Equity method interests (Note 7) ($1,365 and $1,555 related to Altus VIE)	1,365	1,555
Decommissioning security for sold Gulf of Mexico properties (Note 12)	640	0
Deferred charges and other ($6 and $5 related to Altus VIE)	581	526
Note receivable from APA Corporation (Note 2)	1,352	0
Total assets	14,393	12,746
CURRENT LIABILITIES:
Accounts payable ($12 and $6 related to Altus VIE)	651	444
Note payable to APA Corporation (Note 2)	195	0
Current debt	215	2
Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)	1,170	862
Total current liabilities	2,231	1,308
LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)	7,295	8,770
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	148	215
Asset retirement obligation ($68 and $64 related to Altus VIE)	2,089	1,888
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	1,086	0
Other ($67 and $144 related to Altus VIE)	572	602
Total deferred credits and other noncurrent liabilities	3,895	2,705
REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 14)	712	608
EQUITY (DEFICIT):
Common stock, $0.625 par, 1,000 and 860,000,000 shares authorized, 1,000 and 418,429,375 shares issued, respectively	0	262
Paid-in capital	8,677	11,735
Accumulated deficit	(9,317)	(10,461)
Treasury stock, at cost, 0 and 40,946,745 shares, respectively	0	(3,189)
Accumulated other comprehensive income	22	14
DEFICIT ATTRIBUTABLE TO APA CORPORATION	(618)	(1,639)
TOTAL EQUITY (DEFICIT)	260	(645)
Total liabilities and equity	14,393	12,746
Noncontrolling Interest, Egypt
EQUITY (DEFICIT):
Noncontrolling interest	820	925
Noncontrolling Interest, Altus
EQUITY (DEFICIT):
Noncontrolling interest	$ 58	$ 69

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CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Cash and cash equivalent	$ 279	$ 262
Accounts receivable, after allowance for credit loss, current	1,390	908
Other assets, current	649	676
Gathering, processing and transmission facilities	673	670
Other property and equipment	1,126	1,140
Accumulated depreciation, depletion, and amortization	34,213	34,810
Equity method interests	1,365	1,555
Deferred charges and other	581	526
Accounts payable	651	444
Other current liabilities	1,170	862
Long-term debt	7,295	8,770
Asset retirement obligation	2,089	1,888
Other noncurrent liabilities	$ 572	$ 602
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	1,000	860,000,000
Common stock, shares issued (in shares)	1,000	418,429,375
Treasury stock, shares (in shares)	0	40,946,745
Variable Interest Entity, Primary Beneficiary
Cash and cash equivalent	$ 132	$ 24
Accounts receivable, after allowance for credit loss, current	109	95
Other assets, current	9	5
Gathering, processing and transmission facilities	209	206
Other property and equipment	3	3
Accumulated depreciation, depletion, and amortization	25	13
Equity method interests	1,365	1,555
Deferred charges and other	6	5
Accounts payable	12	6
Other current liabilities	15	4
Long-term debt	657	624
Asset retirement obligation	68	64
Other noncurrent liabilities	$ 67	$ 144

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	Noncontrolling Interest, Egypt	Noncontrolling Interest, Altus	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income (Loss)	PARENT COMPANY EQUITY (DEFICIT)	Noncontrolling Interests	Noncontrolling Interests Noncontrolling Interest, Egypt	Noncontrolling Interests Noncontrolling Interest, Altus
Beginning balance at Dec. 31, 2018	$ 0
Increase (Decrease) in Temporary Equity [Roll Forward]
Issuance of Altus Preferred Units	517
Net income attributable to Altus Preferred Unit limited partners	38
Distributions paid to Altus Preferred Unit limited partners		$ (305)									$ (305)
Ending balance at Dec. 31, 2019	555
Beginning balance at Dec. 31, 2018	8,812			$ 260	$ 12,106	$ (2,048)	$ (3,192)	$ 4	$ 7,130	$ 1,682
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income/loss attributable to APA Corporation	(3,553)					(3,553)			(3,553)
Net income (loss) attributable to nonredeemable noncontrolling interest		167	$ (334)								167	$ (334)
Distributions paid to Altus Preferred Unit limited partners		(305)									(305)
Common dividends	(376)				(376)				(376)
Common stock activity, net	(21)			1	(22)				(21)
Compensation expense	61				61				61
Other	14						2	12	14
Ending balance at Dec. 31, 2019	4,465			261	11,769	(5,601)	(3,190)	16	3,255	1,210
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	76
Distributions paid to Altus Preferred Unit limited partners	(23)	(91)									(91)
Ending balance at Dec. 31, 2020	608
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income/loss attributable to APA Corporation	(4,860)					(4,860)			(4,860)
Net income (loss) attributable to nonredeemable noncontrolling interest		(121)	1								(121)	1
Distributions paid to Altus Preferred Unit limited partners	(23)	(91)									(91)
Common dividends	(38)				(38)				(38)
Common stock activity, net	(17)			1	(18)				(17)
Compensation expense	23				23				23
Other	(7)				(1)		1	(2)	(2)	(5)
Ending balance at Dec. 31, 2020	(645)			262	11,735	(10,461)	(3,189)	14	(1,639)	994
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income attributable to Altus Preferred Unit limited partners	162
Distributions paid to Altus Preferred Unit limited partners	(46)	(279)									(279)
Distributions payable to Altus Preferred Unit limited partners	(12)
Ending balance at Dec. 31, 2021	712
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income/loss attributable to APA Corporation	1,062					1,062			1,062
Net income (loss) attributable to nonredeemable noncontrolling interest		174	$ 4								174	$ 4
Distributions paid to Altus Preferred Unit limited partners	(46)	$ (279)									$ (279)
Common dividends	(9)				(9)				(9)
Distributions to APA Corporation	(890)				(890)				(890)
APA Corporation share exchange	0			(262)	(2,927)		3,189
Holding Company Reorganization	839				757	82			839
Other	4				11			8	19	(15)
Ending balance at Dec. 31, 2021	$ 260			$ 0	$ 8,677	$ (9,317)	$ 0	$ 22	$ (618)	$ 878

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STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 0.025	$ 0.10	$ 1.00

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NATURE OF OPERATIONS

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

Nature of Operations

Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Apache’s midstream business (Altus Midstream) 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.

On January 4, 2021, Apache announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the APA’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. Refer to Note 2—Transactions with Parent Affiliate for more detail.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.

Principles of Consolidation

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

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. ALTM is consolidated and qualifies as a variable interest entity (VIE) under GAAP. Additionally, in November of 2021, the Company determined that a limited partnership and Apache subsidiary, which has control over Apache’s Egyptian operations, qualifies as a VIE under GAAP. Apache consolidates the activities of ALTM and Apache’s Egyptian operations because it has concluded that Apache’s subsidiaries have a controlling financial interest in ALTM and APA’s Egyptian operations, respectively, and were determined to be the primary beneficiaries of the VIEs. Additionally, the assets of ALTM may only be used to settle obligations of ALTM. There is no recourse to the Company for ALTM’s liabilities.

Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate 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. The Company regularly reassesses whether changes in the facts and circumstances regarding the Company’s involvement with a VIE could cause a change in its conclusions related to consolidation. Changes in consolidation status, if any, are applied prospectively.

On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 14—Redeemable Noncontrolling Interest — Altus for further detail.

Investments in which the Company holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company’s proportionate share of the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 7—Equity Method Interests for further detail.

Use of Estimates

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

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 3—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation), the estimate of income taxes (refer to Note 11—Income Taxes), the estimation of the contingent liability representing Apache’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 12—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited)).

Fair Value Measurements

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

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

Recurring fair value measurements are presented in further detail in Note 5—Derivative Instruments and Hedging Activities, Note 10—Debt and Financing Costs, Note 13—Retirement and Deferred Compensation Plans, and Note 14—Redeemable Noncontrolling Interest — Altus.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil and gas proved property	$	—	$	4,319	$	1,484
Gathering, processing, and transmission facilities	—		68		1,295
Equity method interests	160		—		—
Divested unproved properties and leasehold	—		—		149
Goodwill	—		87		—
Inventory and other	48		27		21
Total Impairments	$	208	$	4,501	$	2,949

For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in the EPIC crude oil pipeline (EPIC) as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 3—Acquisitions and Divestitures for further detail on the BCP Business Combination. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with non-recurring 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 of $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied 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 in the first quarter of 2020.

During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S.

During the fourth quarter of 2019, following a material reduction to planned investment in Apache’s Alpine High development, the Company recorded impairments totaling $1.4 billion for its Alpine High proved properties and upstream infrastructure which were written down to their fair values. Altus separately assessed its long-lived infrastructure assets for impairment based on expected reductions to future throughput volumes from Alpine High. Altus subsequently recorded impairments totaling $1.3 billion on its GPT facilities. 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.”

Separate from the Company’s Alpine High and Altus impairments, Apache entered into agreements to sell certain of its assets in the Western Anadarko Basin in Oklahoma and Texas. As a result of these agreements, a separate impairment analysis was performed for each of the assets within the disposal groups. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments in the second and fourth quarters of 2019 totaling $255 million, including $101 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. For more information regarding this transaction, refer to Note 3—Acquisitions and Divestitures.

Revenue Recognition

Upstream

The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.

The Company’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

On December 27, 2021, the Company announced the ratification of a modernized PSC with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The Apache subsidiary that became the sole Contractor under the PSC is owned by an Apache-operated joint venture owned two-thirds by Apache and one-third by Sinopec.

Refer to Note 18—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Altus Midstream

The Company’s Altus Midstream segment is operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generates revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on Apache’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represents a single, distinct performance obligation on behalf of Altus that is satisfied over time. In accordance with the terms of these agreements, Altus primarily receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is primarily measured using the output method and recognized in the amount to which Altus has the right to invoice, as performance completed to date corresponds directly with the value to its customers. For the periods presented, Altus Midstream segment revenues were primarily attributable to sales between Altus and Apache, which are fully eliminated upon consolidation.

Payment Terms and Contract Balances

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, totaled $956 million and $670 million as of December 31, 2021 and 2020, respectively.

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.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2021 and 2020, the Company had $279 million and $262 million, respectively, of cash and cash equivalents, of which approximately $132 million and $24 million, respectively, was held by Altus. The Company had no restricted cash as of December 31, 2021 and 2020.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. The Company adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

The following table presents changes to the Company’s allowance for credit loss:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Allowance for credit loss at beginning of year	$	95	$	88	$	92
Additional provisions for the year	19		7		3
Uncollectible accounts written off, net of recoveries	(5)		—		(7)
Allowance for credit loss at end of year	$	109	$	95	$	88

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.

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 2019.

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Proved properties:
U.S.	$	—	$	3,938	$	1,484
Egypt	—		374		—
North Sea	—		7		—
Total proved properties	$	—	$	4,319	$	1,484
Unproved properties:
U.S.	$	22	$	92	$	760
Egypt	8		8		8
North Sea	1		1		—
Total unproved properties	$	31	$	101	$	768

Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively.

Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 3—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission Facilities

GPT facilities totaled $673 million and $670 million at December 31, 2021 and 2020, respectively, with accumulated depreciation for these assets totaling $386 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity to those fields.

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

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

As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment totaled $1.1 billion at each of December 31, 2021 and 2020, with accumulated depreciation for these assets totaling $901 million and $864 million at December 31, 2021 and 2020, respectively.

Asset Retirement Costs and Obligations

The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Capitalized Interest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense.

The following presents the changes to goodwill for the years ended 2020 and 2019:

	Egypt		Total
	(In millions)
Goodwill at December 31, 2018	$	87	$	87
Impairments	—		—
Goodwill at December 31, 2019	87		87
Impairments	(87)		(87)
Goodwill at December 31, 2020	$	—	$	—

Reductions in estimated net present value of expected future cash flows from oil and gas properties during 2020 resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of this assessment, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in 2020. This goodwill impairment was recorded in “Impairments” in the Company’s statement of consolidated operations.

Equity Method Interests

The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company.

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. In the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the announced BCP Business Combination, determined the current fair value of its investment in EPIC was below carrying value. Altus subsequently determined that this loss in value to be other than temporary. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in EPIC. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. Altus has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 7—Equity Method Interests for further details of the Company’s equity method interests.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 12—Commitments and Contingencies.

Derivative Instruments and Hedging Activities

The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.

All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 5—Derivative Instruments and Hedging Activities for further information.

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

Stock-Based Compensation

Prior to consummation of the Holding Company Reorganization, Apache granted various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on APA’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s previous stock-based compensation plans, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock.

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 organization 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 $17 million of reorganization costs were incurred during the year ended December 31, 2021, primarily related to ongoing consulting and separation activities in the Company’s international operations.

The Company recorded $22 million, $54 million, and $50 million of TRS costs in 2021, 2020, and 2019, respectively. TRS costs incurred in 2021 relate to $11 million for consulting costs associated with the reorganization, $6 million of separation costs associated with the reorganization, and $5 million for costs associated with the BCP Business Combination. TRS costs incurred in 2020 relate to $51 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs. TRS costs incurred in 2019 associated with the reorganization include $26 million for employee termination benefits and $2 million for consulting fees. The Company also incurred $15 million of expenses for employee termination benefits and office closures associated with other reorganization efforts and $7 million for consulting and legal fees on various transactions throughout 2019.

New Pronouncements Issued But Not Yet Adopted

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by the discontinuation of the London Interbank Offered Rate (LIBOR) or by another reference rate expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarified the scope and application of the original guidance. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. The Company is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.

In August 2020, the FASB issued ASU 2020-06, “Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40)” to improve financial reporting associated with accounting for convertible instruments and contracts in an entity’s own equity. This update is effective for the Company beginning in the first quarter of 2022 using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company does not believe it will have a material impact on its financial statements.

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TRANSACTIONS WITH PARENT AFFILIATE

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

TRANSACTIONS WITH PARENT AFFILIATE

TRANSACTIONS WITH PARENT AFFILIATE

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

The Company recognized interest income of approximately $51 million on this note during 2021, which is reflected in “Financing costs, net” on the Company’s statement of consolidated operations. Apache allowed interest accrued from March 1, 2021 through August 31, 2021 to PIK pursuant to the note.

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

The Company continues to provide administrative and support operations to APA related to activities performed for the Suriname and Dominican Republic subsidiaries. The Company is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company in connection with its role as service provider. All reimbursements are based on actual costs incurred and no market premium is applied by the Company to APA. The Company incurred $17 million in reimbursable corporate overhead charges during 2021.

In August 2021, Apache entered into a promissory note with APA under which Apache may borrow up to $250 million from APA at APA’s discretion. The note has a term of one year, maturing on August 4, 2022, and bears interest at a variable rate per annum equal to the monthly, short-term applicable federal rate, payable semi-annually. As of December 31, 2021, there was $195 million outstanding under this note, which is reflected as “Note payable to APA Corporation” on the Company’s consolidated balance sheet.

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ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2021

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES

2022 Activity

In February 2022, the Company entered into an agreement to sell certain non-core mineral rights in the Delaware Basin for cash consideration of approximately $805 million, subject to customary post-closing adjustments. The transaction is expected to close in late February 2022, subject to regulatory approvals.

2021 Activity

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

During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions.

During 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.

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

As consideration for the transaction, ALTM will issue 50 million shares of Class C Common Stock (and its subsidiary, Altus Midstream LP, will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.

2020 Activity

During 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million. Also during 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 $87 million, and recognized a gain of $13 million.

2019 Activity

U.S. Divestitures and Leasehold, Property, and Other Acquisitions

In the third quarter of 2019, the Company completed the sale of non-core assets in the Western Anadarko Basin of Oklahoma and Texas for aggregate cash proceeds of approximately $322 million and the assumption of asset retirement obligations of $49 million. These assets met the criteria to be classified as held for sale in the second quarter of 2019. Accordingly, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The transaction closed in the third quarter of 2019, and the Company recognized a $7 million loss in connection with the sale.

In the second quarter of 2019, the Company completed the sale of certain non-core assets in Oklahoma that had a net carrying value of $206 million for aggregate cash proceeds of approximately $223 million. The Company recognized a $17 million gain in connection with the sale.

During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million. The Company recognized a net gain of approximately $33 million upon closing of these transactions.

During 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $40 million.

Suriname Joint Venture Agreement

In December 2019, prior to the Holding Company Reorganization, when Apache’s subsidiaries held interests in Suriname, 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.

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.

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CAPITALIZED EXPLORATORY WELL COSTS

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2021, 2020, and 2019. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Capitalized well costs at beginning of year	$	197	$	141	$	159
Additions pending determination of proved reserves	62		226		286
Divestitures and other	(163)		(38)		(100)
Reclassifications to proved properties	(40)		(56)		(179)
Charged to exploration expense	(10)		(76)		(25)
Capitalized well costs at end of year	$	46	$	197	$	141

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:

	2021		2020		2019
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	13	$	184	$	108
Exploratory well costs capitalized for a period greater than one year	33		13		33
Capitalized well costs at end of year	$	46	$	197	$	141
Number of projects with exploratory well costs capitalized for a period greater than one year	9		5		2

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 reserves can be attributed to these projects. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling were $33 million at December 31, 2021, with $24 million related to exploration and appraisal well activity in the North Sea, where subsurface evaluation and project viability assessment is ongoing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2020 and 2019, relate to onshore projects in Egypt and the U. S. Drilling activity and testing has continued for several of these projects in Egypt throughout 2021, and are currently being evaluated for potential development. The costs related to the U.S. projects were charged to exploration expense based on management’s assessment and development efforts.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2021, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:

	Total		2020		2019		2018 and Prior
	(In millions)
Egypt	$	9	$	—	$	—	$	9
North Sea	24		24		—		—
	$	33	$	24	$	—	$	9

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, 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 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 December 31, 2021, the Company had derivative positions with 10 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 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
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

Foreign Currency Derivative Instruments

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

Embedded Derivatives

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP issued and sold the 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 14—Redeemable Noncontrolling Interest — Altus.

Pipeline Capacity Embedded Derivatives

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

Fair Value Measurements

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2021
Liabilities:
Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Pipeline capacity embedded derivatives	—		46		—		46		—		46
Preferred Units embedded derivative	—		—		57		57		—		57
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivatives	—		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. The fair value 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, any anticipated early redemptions of the Preferred Units, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the December 31, 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 at December 31, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	57	Option Model	Altus’ Imputed Interest Rate	5.54-11.21%
				Interest Rate Volatility	40.08%

In addition, no early redemptions of the Preferred Units were assumed for the December 31, 2020 valuation. As a result of the announced BCP Business Combination and associated publicly filed information, the December 31, 2021 valuation assumed 250,000 Preferred Units would be redeemed before the Preferred Unit holders had the right to exercise their exchange option. This early redemption assumption significantly reduced the value of the derivative liability year over year.

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of December 31, 2021, while a one percent decrease would lead to a similar decrease in value as of December 31, 2021. The assumed expected timing until exercise of the exchange option at December 31, 2021 was 4.45 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:

	For the Year Ended December 31,
	2021		2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	4	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	109		192
Total derivative liabilities	$	113	$	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 Year Ended December 31,
	2021		2020		2019
	(In millions)
Realized:
Commodity derivative instruments	$	25	$	(135)	$	27
Foreign currency derivative instruments	—		(1)		—
Treasury-lock	—		—		(18)
Realized gain (loss), net	25		(136)		9
Unrealized:
Commodity derivative instruments	(20)		11		(44)
Pipeline capacity embedded derivatives	7		(61)		8
Foreign currency derivative instruments	—		(1)		1
Preferred Units embedded derivative	82		(36)		(9)
Unrealized gain (loss), net	69		(87)		(44)
Derivative instrument gains (losses), net	$	94	$	(223)	$	(35)

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

The Company seeks to maintain a balance between “first of month” and “gas daily pricing” for its U.S. natural gas portfolio and sales activities in a given month as part of its ordinary course of business. This is typically implemented through a combination of physical and financial contracts that settle monthly.

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OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2021

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

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of December 31:

	2021		2020
	(In millions)
Inventories	$	438	$	492
Drilling advances	55		113
Prepaid assets and other	56		71
Current decommissioning security for sold Gulf of Mexico assets	100		—
Total Other current assets	$	649	$	676

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EQUITY METHOD INTERESTS

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INTERESTS

EQUITY METHOD INTERESTS

As of December 31, 2021 and 2020, Apache, through its ownership of Altus, has 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.

	Interest		2021		2020
			(In millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	274	$	284
EPIC Crude Holdings, LP	15.0	%	—		176
Permian Highway Pipeline LLC	26.7	%	630		615
Shin Oak Pipeline (Breviloba, LLC)	33.0	%	461		480
Total Altus equity method interests			$	1,365	$	1,555

As of December 31, 2021 and 2020, unamortized basis differences included in the equity method interest balances were $34 million and $38 million, respectively. These amounts represent differences in Altus’ initial costs paid to acquire the equity method interests and its initial underlying equity in the respective entities, as well as capitalized interest related to Permian Highway Pipeline (PHP) construction costs. Unamortized basis differences are amortized into equity income (loss) over the useful lives of the underlying pipeline assets when they are placed into service.

The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2021 and 2020:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2019	$	291	$	163	$	311	$	493	$	1,258
Capital contributions	2		29		296		—		327
Distributions	(51)		—		—		(46)		(97)
Capitalized interest(1)	—		—		8		—		8
Equity income (loss), net	42		(16)		—		33		59
Balance at December 31, 2020	284		176		615		480		1,555
Capital contributions	—		2		26		—		28
Distributions	(50)		—		(74)		(49)		(173)
Equity income (loss), net	40		(19)		63		30		114
Accumulated other comprehensive loss	—		1		—		—		1
Impairment(2)	—		(160)		—		—		(160)
Balance at December 31, 2021	$	274	$	—	$	630	$	461	$	1,365

(1)Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million of related interest expense during 2020, which is included in the basis of the PHP equity interest.

(2)The Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies for further details on this impairment charge.

Summarized Combined Financial Information

The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis):

	For the Year Ended December 31,
	2021		2020		2019(1)
	(In millions)
Operating revenues	$	1,082	$	707	$	302
Operating income	548		331		121
Net income	468		256		120
Other comprehensive income (loss)	4		3		(8)

(1)Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the full year ended December 31, 2019 for comparability.

The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31:

	2021		2020
	(In millions)
Current assets	$	280	$	260
Noncurrent assets	7,445		7,678
Total assets	$	7,725	$	7,938
Current liabilities	$	153	$	206
Noncurrent liabilities	1,193		1,191
Equity	6,379		6,541
Total liabilities and equity	$	7,725	$	7,938

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OTHER CURRENT LIABILITIES

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of December 31:

	2021		2020
	(In millions)
Accrued operating expenses	$	129	$	91
Accrued exploration and development	206		167
Accrued compensation and benefits	292		170
Accrued interest	107		140
Accrued income taxes	28		25
Current asset retirement obligation	41		56
Current operating lease liability	99		116
Current decommissioning contingency for sold Gulf of Mexico properties	100		—
Other	168		97
Total Other current liabilities	$	1,170	$	862

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION

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

	For the Year Ended December 31,
	2021		2020
	(In millions)
Asset retirement obligation at beginning of the year	$	1,944	$	1,858
Liabilities incurred	3		10
Liabilities divested	(44)		(26)
Liabilities settled	(32)		(30)
Accretion expense	113		109
Revisions in estimated liabilities	146		23
Asset retirement obligation at end of the year	2,130		1,944
Less current portion	(41)		(56)
Asset retirement obligation, long-term	$	2,089	$	1,888

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.

During 2021 and 2020, the Company recorded $3 million and $10 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2021, approximately $146 million net abandonment costs were revised upward to reflect changes in estimates of higher current activity costs and long-term inflation assumptions, primarily in the U.S. During 2020, approximately $23 million net abandonment costs were revised upward to reflect changes in estimates of timing and costs, primarily in the North Sea.

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DEBT AND FINANCING COSTS

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

DEBT AND FINANCING COSTS

Overview

The debt of Apache and Altus Midstream LP is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company to repurchase outstanding notes and debentures upon certain changes in control. None of the indentures contain prepayment obligations in the event of a decline in credit ratings.

On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

On June 21, 2019, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases.

On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s senior revolving credit facility, and for general corporate purposes.

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

During 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under the Company’s revolving credit facility.

During the quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.

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

The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations.

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

	December 31,
	2021		2020
	(In millions)
3.25% notes due 2022(1)(2)	$	213	$	213
2.625% notes due 2023(2)	123		123
4.625% notes due 2025(2)	500		500
7.7% notes due 2026	79		79
7.95% notes due 2026	133		133
4.875% due 2027(2)	378		750
4.375% notes due 2028(2)	703		993
7.75% notes due 2029(2)(3)	235		235
4.25% notes due 2030(2)	580		580
6.0% notes due 2037(2)	443		443
5.1% notes due 2040(2)	1,333		1,333
5.25% notes due 2042(2)	399		399
4.75% notes due 2043(2)	428		1,133
4.25% notes due 2044(2)	221		559
7.375% debentures due 2047	150		150
5.35% notes due 2049(2)	387		390
7.625% debentures due 2096	39		39
Notes and debentures before unamortized discount and debt issuance costs(4)	6,344		8,052
Commercial paper	—		—
Altus credit facility(5)	657		624
Apache credit facility(5)	542		150
Finance lease obligations	36		38
Unamortized discount	(30)		(35)
Debt issuance costs	(39)		(57)
Total debt	7,510		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,295	$	8,770

(1)On January 18, 2022, Apache redeemed the 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.

(2)These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.

(3)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.

(4)The fair values of Apache’s notes and debentures were $7.1 billion and $8.5 billion as of December 31, 2021 and 2020, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

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

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2021 are as follows:

	(In millions)
2022	$	213
2023	123
2024	—
2025	500
2026	212
Thereafter	5,296
Notes and debentures, excluding discounts and debt issuance costs	$	6,344

Uncommitted Lines of Credit

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

Unsecured Committed Bank 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 December 31, 2021. The facility is for general corporate purposes. As of December 31, 2021, there were $542 million of borrowings and an aggregate of £748 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate of £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit 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.

At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the LIBOR, plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon Apache’s senior long-term debt rating. At December 31, 2021, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

The financial covenants of the 2018 credit facility require Apache to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015.

The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.9 billion as of December 31, 2021. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

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 December 31, 2021, there were $657 million of borrowings and a $2.0 million of 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 agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to ALTM and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00.

The terms of Altus Midstream LP’s Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by ALTM and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 14—Redeemable Noncontrolling Interest — Altus for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners. 

The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA Corporation, Apache or any of APA Corporation’s other subsidiaries.

There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2021.

Commercial Paper Program

As of December 31, 2020, Apache had no commercial paper outstanding. Apache did not use its commercial paper program in 2021 and terminated the program during the third quarter of 2021.

Financing Costs, Net

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Interest expense	$	419	$	438	$	430
Amortization of debt issuance costs	8		8		7
Capitalized interest	—		(12)		(37)
Loss (gain) on extinguishment of debt	104		(160)		75
Interest income	(8)		(7)		(13)
Interest income from APA Corporation, net	(51)		—		—
Financing costs, net	$	472	$	267	$	462

As of December 31, 2021, the Company had $39 million of debt issuance costs, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $6 million, $7 million, and $2 million was recorded as interest expense in 2021, 2020, and 2019, respectively.

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INCOME TAXES

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Income (loss) before income taxes is composed of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
U.S.	$	689	$	(4,581)	$	(4,397)
Foreign	1,291		(259)		1,389
Total	$	1,980	$	(4,840)	$	(3,008)

The total income tax provision consists of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Current income taxes:
Federal	$	16	$	(2)	$	1
Foreign	636		178		659
	652		176		660
Deferred income taxes:
Federal	—		—		67
Foreign	(74)		(112)		(53)
	(74)		(112)		14
Total	$	578	$	64	$	674

The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	416	$	(1,016)	$	(631)
State income tax, less federal effect(1)	—		—		1
Taxes related to foreign operations	300		97		328
Tax credits	(10)		(13)		(6)
Net change in tax contingencies	16		1		1
Goodwill impairment	—		35		—
Valuation allowances(1)	(111)		965		972
Tax attributable to Altus Preferred Unit limited partners	(34)		(16)		(8)
All other, net	1		11		17
	$	578	$	64	$	674

(1)The change in state valuation allowance is included as a component of state income tax.

The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax liability consists of the following as of December 31:

	2021		2020
	(In millions)
Deferred tax assets:
U.S. and state net operating losses	$	2,494	$	2,306
Capital losses	647		633
Tax credits and other tax incentives	24		33
Foreign tax credits	2,241		2,241
Accrued expenses and liabilities	152		93
Asset retirement obligation	712		654
Property and equipment	3		261
Investment in Altus Midstream LP	64		76
Net interest expense limitation	135		252
Lease liability	81		79
Decommissioning contingency for sold Gulf of Mexico properties	263		—
Other	1		1
Total deferred tax assets	6,817		6,629
Valuation allowance	(5,875)		(5,991)
Net deferred tax assets	942		638
Deferred tax liabilities:
Equity investments	2		4
Property and equipment	748		750
Right-of-use asset	77		74
Decommissioning security for sold Gulf of Mexico properties	164		—
Other	86		13
Total deferred tax liabilities	1,077		841
Net deferred income tax liability	$	135	$	203

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:

	2021		2020
	(In millions)
Assets:
Deferred charges and other	$	13	$	12
Liabilities:
Income taxes	148		215
Net deferred income tax liability	$	135	$	203

The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize existing deferred tax assets. A significant piece of negative evidence evaluated was the pre-tax book cumulative loss incurred over the three-year period ended December 31, 2021. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth.

In 2021, 2020, and 2019, the Company’s valuation allowance decreased by $116 million, increased by $1.0 billion, and increased by $1.0 billion, respectively, as detailed in the table below:

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	5,991	$	4,959	$	3,947
State(1)	1		67		41
U.S.	(112)		960		971
Foreign	(5)		5		—
Balance at end of year	$	5,875	$	5,991	$	4,959

(1)Reported as a component of state income taxes.

On December 31, 2021, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
U.S.	$	9,717	2021 - Indefinite
State	6,695		Various
Foreign	1		2028 - Indefinite

The Company has a U.S. net operating loss carryforward of $9.7 billion, which includes $177 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has a net interest expense carryover of $610 million under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.9 billion, which has a five year carryover period expiring in 2023 and a Canadian capital loss carryforward of $836 million which has an indefinite carryover. The Company has recorded a full valuation allowance against the U.S. net operating losses, the state net operating losses, the net interest expense carryover, the U.S. capital loss, and the Canadian capital loss because it is more likely than not that these attributes will not be realized.

On December 31, 2021, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,241	2025-2026

The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a full valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold that a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	93	$	82	$	24
Additions based on tax positions related to prior year	16		—		49
Additions based on tax positions related to the current year	7		11		9
Balance at end of year	$	116	$	93	$	82

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2021, 2020, and 2019, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2021, 2020, and 2019, the Company had an accrued liability for interest and penalties of $4 million, $3 million, and $2 million, respectively.

In 2021, 2020, and 2019, the Company recorded a $23 million net increase, an $11 million net increase, and a $58 million net increase, respectively, in its reserve for uncertain tax positions. The Company is currently under IRS audit for the 2014 through 2017 tax years.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. Apache’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction

U.S.	2014
Egypt	2005
U.K.	2020

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory control, which also may include controls related to the potential impacts of climate changes. As of December 31, 2021, the Company has an accrued liability of approximately $84 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.

Argentine Environmental Claims

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration 

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

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

Apollo Exploration Lawsuit

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

Australian Operations Divestiture Dispute

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

Canadian Operations Divestiture Dispute

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

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases 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. After removal of this lawsuit to federal court, the district court remanded it back to state court. The remand order is being appealed to the 3rd Circuit Court of Appeals. Further activity in the case has been stayed pending this appellate review.

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

Castex Lawsuit

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

Oklahoma Class Actions

The Company is a party to two purported class actions in Oklahoma styled Bigie Lee Rhea v. Apache Corporation, Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219. The Rhea case has been certified and includes a class of royalty owners seeking damages of approximately $200 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Rhea case under which Apache will pay $25 million to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized in the first quarter of 2022.

Shareholder and Derivative Lawsuits

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

On March 16, 2021, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 334th District Court of Harris County, Texas. The case purports to be a derivative action brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe the plaintiff’s claims lack merit and intend to vigorously defend this lawsuit.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.

As of December 31, 2021, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

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

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

The Company is not aware of any environmental claims existing as of December 31, 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 Decommissioning Obligations on Sold Properties

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

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

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

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

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

As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.

Leases and Contractual Obligations

On January 1, 2019, Apache adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. As allowed under the standard, the Company applied practical expedients permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as permitting an entity the option to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs.

The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, Apache records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, Apache enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable.

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $127 million, $149 million, and $222 million for the full years of 2021, 2020, and 2019, respectively. Apache elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation.

In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million, $2 million, and $7 million in 2021, 2020, and 2019, respectively. Interest on the Company’s finance lease asset was $2 million, $2 million, and $3 million in 2021, 2020, and 2019, respectively.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2021:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		11.7 years
Weighted average discount rate	3.7	%	4.4	%

At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)	Operating Leases(2)		Finance Leases(3)		Purchase Obligations(4)(5)
	(In millions)
2022	$	106	$	3	$	230
2023	75		3		199
2024	58		3		161
2025	7		4		159
2026	7		4		3,637
Thereafter	18		25		463
Total future minimum payments	271		42		$	4,849
Less: imputed interest	(22)		(6)		N/A
Total lease liabilities	249		36		N/A
Current portion	99		2		N/A
Non-current portion	$	150	$	34	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $194 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.

(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $63 million, $41 million and $78 million in 2021, 2020, and 2019, respectively.

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RETIREMENT AND DEFERRED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

RETIREMENT AND DEFERRED COMPENSATION PLANS

RETIREMENT AND DEFERRED COMPENSATION PLANS

The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of eligible employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a qualifying change in control of ownership of APA, immediate and full vesting occurs.

Additionally, Apache North Sea Limited maintains a separate retirement plan, as required under the laws of the U.K.

The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $31 million, $43 million, and $52 million for 2021, 2020, and 2019, respectively.

The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2021, 2020, and 2019, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	233		$	20		$	199		$	20		$	187		$	27
Service cost	3			1			3			1			3			2
Interest cost	3			—			4			—			5			1
Foreign currency exchange rates	(2)			—			8			—			7			—
Actuarial losses (gains)	(5)			1			30			1			15			(9)
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Projected benefit obligation at end of year	211			20			233			20			199			20
Change in Plan Assets
Fair value of plan assets at beginning of year	262			—			228			—			208			—
Actual return on plan assets	11			—			31			—			25			—
Foreign currency exchange rates	(3)			—			9			—			8			—
Employer contributions	5			2			5			2			5			1
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Fair value of plan assets at end of year	254			—			262			—			228			—
Funded status at end of year	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	43			(18)			29			(18)			29			(18)
	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	1		$	14		$	(11)		$	16		$	(7)		$	19
Weighted Average Assumptions used as of December 31
Discount rate	1.80		%	2.57		%	1.40		%	2.06		%	2.10		%	3.00		%
Salary increases	4.90		%	N/A			4.50		%	N/A			4.30		%	N/A
Expected return on assets	1.90		%	N/A			1.50		%	N/A			2.20		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.00		%	N/A			6.25		%
Ultimate in 2028	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

As of December 31, 2021, 2020, and 2019, the accumulated benefit obligation for the U.K. Pension Plan was $205 million, $207 million, and $181 million, respectively.

The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in a blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:

	Target Allocation		Percentage of Plan Assets at Year-End
	2021		2021		2020
Asset Category
Equity securities:
Overseas quoted equities	15	%	15	%	19	%
Total equity securities	15	%	15	%	19	%
Debt securities:
U.K. government bonds	55	%	54	%	64	%
U.K. corporate bonds	24	%	25	%	16	%
Total debt securities	79	%	79	%	80	%
Cash	6	%	6	%	1	%
Total	100	%	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2021 and 2020 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2021 and 2020:

	December 31,
	2021		2020
	(In millions)
Equity securities:
Overseas quoted equities	$	38	$	49
Total equity securities	38		49
Debt securities:
U.K. government bonds	138		168
U.K. corporate bonds	62		43
Total debt securities	200		211
Cash	16		2
Fair value of plan assets	$	254	$	262

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year.

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2021, 2020, and 2019: 

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	3		$	1		$	3		$	1		$	3		$	2
Interest cost	3			—			4			—			5			1
Expected return on assets	(4)			—			(5)			—			(5)			—
Amortization of loss	—			(1)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	2		$	—		$	2		$	—		$	3		$	2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	1.40		%	2.06		%	2.10		%	3.00		%	2.90		%	4.13		%
Salary increases	4.50		%	N/A			4.30		%	N/A			4.70		%	N/A
Expected return on assets	1.50		%	N/A			2.20		%	N/A			2.80		%	N/A
Healthcare cost trend
Initial	N/A			6.00		%	N/A			6.25		%	N/A			6.50		%
Ultimate in 2025	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

Apache expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2022. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2022	$	6	$	2
2023	7		2
2024	6		2
2025	6		2
2026	6		2
Years 2027-2031	39		6

XML

REDEMABLE NONCONTROLLING INTEREST - ALTUS

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

REDEMABLE NONCONTROLLING INTEREST - ALTUS

REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

•The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

•The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

•The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

•Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

•Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

•Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $57 million as of December 31, 2021. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. Refer to Note 5—Derivative Instruments and Hedging Activities for more detail.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent 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 for the years ended December 31, 2021 and 2020 is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units: at December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions paid to Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream net income	N/A	76
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment	N/A	82
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2021	660,694	712
Preferred Units embedded derivative(2)		57
		$	769

(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of December 31, 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 December 31, 2021, the Redemption Price would have been based on an 11.5 percent internal rate of return, which would equate to a redemption value of $739 million.

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

N/A - not applicable.

CAPITAL STOCK AND EQUITY

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

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

Net Income (Loss) per Common Share

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

Common Stock Dividend

In the first quarter of 2020, Apache’s board of directors (Board of Directors) approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the year ended December 31, 2021, the Company paid $43 million in capital distributions to its parent, APA, which is included as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

Stock Compensation Plans

Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, including stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting.

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2021, 11.0 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Stock-settled and cash-settled compensation expensed	$	152	$	40	$	110
Stock-settled and cash-settled compensation capitalized	18		7		28
Total stock-settled and cash-settled compensation costs	$	170	$	47	$	138

Stock Options

As of December 31, 2021, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan and, collectively with the 2016 Plan and the 2011 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

The following table summarizes stock option activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price
	(In thousands, except exercise price amounts)
Outstanding, beginning of year	3,537	$	72.10	4,298	$	75.24	4,872	$	75.95
Forfeited	—	—		(37)	44.98		(80)	34.58
Expired	(525)	119.83		(724)	92.14		(494)	88.82
Outstanding, end of year(1)	3,012	63.79		3,537	72.10		4,298	75.24
Expected to vest	—	—		150	45.77		495	49.11
Exercisable, end of year(2)	3,012	63.79		3,387	73.26		3,803	78.64

(1)As of December 31, 2021, options outstanding had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

(2)As of December 31, 2021, options exercisable had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

There were no options issued and no options exercised during the years ended December 31, 2021, 2020, and 2019.

Restricted Stock Units and Restricted Stock Phantom Units

Prior to consummation of the Holding Company Reorganization, the Company had restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either APA’s common stock or in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

For the years ended December 31, 2021, 2020, and 2019, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $91 million, $39 million, and $104 million, respectively. As of December 31, 2021, 2020, and 2019, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $15 million, $6 million, and $24 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value
	(In thousands, except per share amounts)
Non-vested, beginning of year	1,552	$	28.43	2,448	$	46.65	3,153	$	55.54
Granted	1,506	16.46		1,352	24.60		1,479	36.81
Vested(3)	(857)	29.13		(1,933)	48.65		(1,899)	53.99
Forfeited	(128)	19.78		(315)	30.09		(285)	45.06
Non-vested, end of year(1)(2)	2,073	19.98		1,552	28.43		2,448	46.65

(1)As of December 31, 2021, there was $14 million of total unrecognized compensation cost related to 2,073,419 unvested stock-settled restricted stock units.

(2)As of December 31, 2021, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2021, 2020, and 2019 were approximately $25 million, $94 million, and $103 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2021, 2020, and 2019:

	For the Year Ended December 31,
	2021	2020	2019
	(In thousands)
Non-vested, beginning of year	4,423	5,384	1,818
Adjustment for ALTM reverse stock split(1)	—	(1,246)	—
Granted(2)	4,441	3,462	4,831
Vested	(2,049)	(1,618)	(616)
Forfeited	(413)	(1,559)	(649)
Non-vested, end of year(3)	6,402	4,423	5,384

(1)On June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock.

(2)Restricted stock phantom units granted during 2021 and 2020 included 4,375,546 and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 65,327 and 83,239 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2021 was approximately $74 million.

In January 2022, APA awarded 775,942 restricted stock units and 2,512,602 restricted stock phantom units based on APA’s weighted-average per-share market price of $29.46 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $23 million and $76 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of APA’s common stock.

Also during January 2022, APA awarded 27,643 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $63.63. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $2 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of ALTM’s common stock.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2021, are as described below:

•In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 1,868 restricted stock units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 54 percent of target.

•In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 97,645 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 23 percent of target.

•In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 1,247,706 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 100 percent of target.

•In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,330,823 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 2,661,646 phantom units could be awarded.

•In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,854,736 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 3,709,472 units could be awarded.

The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the performance programs were an expense of $56 million, a credit of $8 million, and an expense of $24 million during 2021, 2020, and 2019, respectively. Capitalized compensation costs under the performance programs were an expense of $3 million, a credit of $1 million, and an expense of $3 million during 2021, 2020, and 2019, respectively.

The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2021:

	Units
	(In thousands)
Non-vested, beginning of year	3,417
Granted	1,782
Vested	(76)
Forfeited	(240)
Expired	(352)
Non-vested, end of year(1)	4,531

(1)As of December 31, 2021, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $36 million.

In January 2022, APA’s board of directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Payout for 50 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 2,186,068 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $41.88 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $29.46 based on the weighted-average fair market value of a share of common stock of APA as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.

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CAPITAL STOCK AND EQUITY

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

CAPITAL STOCK AND EQUITY

REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:

•The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.

•The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.

•The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

•Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

•Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.

•Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.

Classification

The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Initial Measurement

Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.

Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $57 million as of December 31, 2021. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. Refer to Note 5—Derivative Instruments and Hedging Activities for more detail.

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	517
Preferred Units embedded derivative	94
	$	611

Subsequent 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 for the years ended December 31, 2021 and 2020 is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units: at December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions paid to Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream net income	N/A	76
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment	N/A	82
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2021	660,694	712
Preferred Units embedded derivative(2)		57
		$	769

(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of December 31, 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 December 31, 2021, the Redemption Price would have been based on an 11.5 percent internal rate of return, which would equate to a redemption value of $739 million.

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

N/A - not applicable.

CAPITAL STOCK AND EQUITY

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

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

Net Income (Loss) per Common Share

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

Common Stock Dividend

In the first quarter of 2020, Apache’s board of directors (Board of Directors) approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the first quarter of 2021, prior to completion of the Holding Company Reorganization, the Company paid $9 million in dividends on its common stock. During the year ended December 31, 2021, the Company paid $43 million in capital distributions to its parent, APA, which is included as “Distributions to APA Corporation” on the Company’s statement of consolidated cash flows.

Stock Compensation Plans

Prior to consummation of the Holding Company Reorganization, the Company maintained several stock-based compensation plans, including stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting.

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2021, 11.0 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Stock-settled and cash-settled compensation expensed	$	152	$	40	$	110
Stock-settled and cash-settled compensation capitalized	18		7		28
Total stock-settled and cash-settled compensation costs	$	170	$	47	$	138

Stock Options

As of December 31, 2021, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan and, collectively with the 2016 Plan and the 2011 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

The following table summarizes stock option activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price
	(In thousands, except exercise price amounts)
Outstanding, beginning of year	3,537	$	72.10	4,298	$	75.24	4,872	$	75.95
Forfeited	—	—		(37)	44.98		(80)	34.58
Expired	(525)	119.83		(724)	92.14		(494)	88.82
Outstanding, end of year(1)	3,012	63.79		3,537	72.10		4,298	75.24
Expected to vest	—	—		150	45.77		495	49.11
Exercisable, end of year(2)	3,012	63.79		3,387	73.26		3,803	78.64

(1)As of December 31, 2021, options outstanding had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

(2)As of December 31, 2021, options exercisable had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

There were no options issued and no options exercised during the years ended December 31, 2021, 2020, and 2019.

Restricted Stock Units and Restricted Stock Phantom Units

Prior to consummation of the Holding Company Reorganization, the Company had restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either APA’s common stock or in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

For the years ended December 31, 2021, 2020, and 2019, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $91 million, $39 million, and $104 million, respectively. As of December 31, 2021, 2020, and 2019, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $15 million, $6 million, and $24 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value
	(In thousands, except per share amounts)
Non-vested, beginning of year	1,552	$	28.43	2,448	$	46.65	3,153	$	55.54
Granted	1,506	16.46		1,352	24.60		1,479	36.81
Vested(3)	(857)	29.13		(1,933)	48.65		(1,899)	53.99
Forfeited	(128)	19.78		(315)	30.09		(285)	45.06
Non-vested, end of year(1)(2)	2,073	19.98		1,552	28.43		2,448	46.65

(1)As of December 31, 2021, there was $14 million of total unrecognized compensation cost related to 2,073,419 unvested stock-settled restricted stock units.

(2)As of December 31, 2021, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2021, 2020, and 2019 were approximately $25 million, $94 million, and $103 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2021, 2020, and 2019:

	For the Year Ended December 31,
	2021	2020	2019
	(In thousands)
Non-vested, beginning of year	4,423	5,384	1,818
Adjustment for ALTM reverse stock split(1)	—	(1,246)	—
Granted(2)	4,441	3,462	4,831
Vested	(2,049)	(1,618)	(616)
Forfeited	(413)	(1,559)	(649)
Non-vested, end of year(3)	6,402	4,423	5,384

(1)On June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock.

(2)Restricted stock phantom units granted during 2021 and 2020 included 4,375,546 and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 65,327 and 83,239 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2021 was approximately $74 million.

In January 2022, APA awarded 775,942 restricted stock units and 2,512,602 restricted stock phantom units based on APA’s weighted-average per-share market price of $29.46 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $23 million and $76 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of APA’s common stock.

Also during January 2022, APA awarded 27,643 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $63.63. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $2 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of ALTM’s common stock.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. Apache has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2021, are as described below:

•In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 1,868 restricted stock units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 54 percent of target.

•In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 97,645 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 23 percent of target.

•In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 1,247,706 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 100 percent of target.

•In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,330,823 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 2,661,646 phantom units could be awarded.

•In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,854,736 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 3,709,472 units could be awarded.

The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the performance programs were an expense of $56 million, a credit of $8 million, and an expense of $24 million during 2021, 2020, and 2019, respectively. Capitalized compensation costs under the performance programs were an expense of $3 million, a credit of $1 million, and an expense of $3 million during 2021, 2020, and 2019, respectively.

The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2021:

	Units
	(In thousands)
Non-vested, beginning of year	3,417
Granted	1,782
Vested	(76)
Forfeited	(240)
Expired	(352)
Non-vested, end of year(1)	4,531

(1)As of December 31, 2021, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $36 million.

In January 2022, APA’s board of directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Payout for 50 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 2,186,068 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $41.88 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $29.46 based on the weighted-average fair market value of a share of common stock of APA as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Components of accumulated other comprehensive income (loss) include the following:

	As of December 31,
	2021		2020		2019
	(In millions)
Share of equity method interests other comprehensive loss	$	—	$	(1)	$	(1)
Pension and postretirement benefit plan (Note 13)	22		15		17
Accumulated other comprehensive income	$	22	$	14	$	16

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MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2021

Risks and Uncertainties [Abstract]

MAJOR CUSTOMERS

MAJOR CUSTOMERS

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP PLC and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.

Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.

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BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

BUSINESS SEGMENT INFORMATION

As of December 31, 2021, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces natural gas, crude oil, and NGLs. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration	63		34		28		—		2		127
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(128)		5,097
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(2)	2,888
Other Income (Expense):
Gain on divestitures, net											67
Loss on previously sold Gulf of Mexico properties											(446)
Derivative instrument gain, net											94
Other											228
General and administrative											(357)
Transaction, reorganization, and separation											(22)
Financing costs, net											(472)
Income Before Income Taxes											$	1,980
Total Assets(3)	$	2,796	$	2,199	$	7,700	$	1,698	$	—	$	14,393
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	—	$	8,060
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	—	$	1,004

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2020
Oil revenues	$	1,102	$	795	$	1,209	$	—	$	—	$	3,106
Natural gas revenues	280		67		251		—		—		598
Natural gas liquids revenues	8		21		304		—		—		333
Oil, natural gas, and natural gas liquids production revenues	1,390		883		1,764		—		—		4,037
Purchased oil and gas sales	—		—		394		4		—		398
Midstream service affiliate revenues	—		—		—		145		(145)		—
	1,390		883		2,158		149		(145)		4,435
Operating Expenses:
Lease operating expenses	424		305		400		—		(2)		1,127
Gathering, processing, and transmission	38		50		291		38		(143)		274
Purchased oil and gas costs	—		—		354		3		—		357
Taxes other than income	—		—		108		15		—		123
Exploration	63		28		168		—		15		274
Depreciation, depletion, and amortization	601		380		779		12		—		1,772
Asset retirement obligation accretion	—		73		32		4		—		109
Impairments	529		7		3,963		2		—		4,501
	1,655		843		6,095		74		(130)		8,537
Operating Income (Loss)	$	(265)	$	40	$	(3,937)	$	75	$	(15)	(4,102)
Other Income (Expense):
Gain on divestitures, net											32
Derivative instrument losses, net											(223)
Other											64
General and administrative											(290)
Transaction, reorganization, and separation											(54)
Financing costs, net											(267)
Loss Before Income Taxes											$	(4,840)
Total Assets(3)	$	3,003	$	2,220	$	5,540	$	1,786	$	197	$	12,746
Net Property and Equipment	$	1,955	$	1,773	$	4,760	$	196	$	135	$	8,819
Additions to Net Property and Equipment	$	454	$	215	$	345	$	12	$	136	$	1,162

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2019
Oil revenues	$	1,969	$	1,163	$	2,098	$	—	$	—	$	5,230
Natural gas revenues	295		90		293		—		—		678
Natural gas liquids revenues	12		23		372		—		—		407
Oil, natural gas, and natural gas liquids production revenues	2,276		1,276		2,763		—		—		6,315
Purchased oil and gas sales	—		—		176		—		—		176
Midstream service affiliate revenues	—		—		—		136		(136)		—
	2,276		1,276		2,939		136		(136)		6,491
Operating Expenses:
Lease operating expenses	484		320		645		—		(2)		1,447
Gathering, processing, and transmission	40		45		299		56		(134)		306
Purchased oil and gas costs	—		—		142		—		—		142
Taxes other than income	—		—		194		13		—		207
Exploration	100		2		688		—		15		805
Depreciation, depletion, and amortization	708		366		1,566		40		—		2,680
Asset retirement obligation accretion	—		76		29		2		—		107
Impairments	—		—		1,648		1,301		—		2,949
	1,332		809		5,211		1,412		(121)		8,643
Operating Income (Loss)	$	944	$	467	$	(2,272)	$	(1,276)	$	(15)	(2,152)
Other Income (Expense):
Gain on divestitures, net											43
Derivative instrument losses, net											(35)
Other											54
General and administrative											(406)
Transaction, reorganization, and separation											(50)
Financing costs, net											(462)
Loss Before Income Taxes											$	(3,008)
Total Assets(3)	$	3,700	$	2,473	$	10,388	$	1,479	$	67	$	18,107
Net Property and Equipment	$	2,573	$	1,956	$	9,385	$	206	$	38	$	14,158
Additions to Net Property and Equipment	$	454	$	183	$	1,696	$	308	$	93	$	2,734

(1)Includes revenue from non-customers for the years ended December 31, 2021, 2020, and 2019 of:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil	$	420	$	95	$	410
Natural gas	47		14		40
Natural gas liquids	2		—		1

(2)Includes a noncontrolling interest in Egypt and Altus Midstream.

(3)Intercompany balances are excluded from total assets.

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions, except per boe)
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		2		127
Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		2		4,278
Results of operations	$	1,440	$	585	$	200	$	(2)	$	2,223
2020
Oil and gas production revenues	$	1,764	$	1,390	$	883	$	—	$	4,037
Operating cost:
Depreciation, depletion, and amortization(2)	726		540		377		—		1,643
Asset retirement obligation accretion	32		—		73		—		105
Lease operating expenses	400		424		305		—		1,129
Gathering, processing, and transmission	291		38		50		—		379
Exploration expenses	168		63		28		15		274
Impairments related to oil and gas properties	3,938		374		7		—		4,319
Production taxes(3)	106		—		—		—		106
Income tax	(818)		(22)		17		—		(823)
	4,843		1,417		857		15		7,132
Results of operations	$	(3,079)	$	(27)	$	26	$	(15)	$	(3,095)
2019
Oil and gas production revenues	$	2,763	$	2,276	$	1,276	$	—	$	6,315
Operating cost:
Depreciation, depletion, and amortization(2)	1,508		641		363		—		2,512
Asset retirement obligation accretion	29		—		76		—		105
Lease operating expenses	645		484		320		—		1,449
Gathering, processing, and transmission	299		40		45		—		384
Exploration expenses	688		100		2		15		805
Impairments related to oil and gas properties	1,633		—		—		—		1,633
Production taxes(3)	191		—		—		—		191
Income tax	(468)		455		188		—		175
	4,525		1,720		994		15		7,254
Results of operations	$	(1,762)	$	556	$	282	$	(15)	$	(939)

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 18—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 18—Business Segment Information.

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities

	United States		Egypt(2)		North Sea		Other International		Total(2)
	(In millions)
2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		30		161
Development	545		404		135		1		1,085
Costs incurred(1)	$	560	$	353	$	174	$	31	$	1,118
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	—	$	—
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts - Proved and Unproved	—		(145)		—		—		(145)
2020
Acquisitions:
Proved	$	—	$	7	$	—	$	—	$	7
Unproved	4		—		—		—		4
Exploration	8		102		68		150		328
Development	332		378		162		—		872
Costs incurred(1)	$	344	$	487	$	230	$	150	$	1,211
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—	$	—	$	—	$	3	$	3
Asset retirement costs	9		—		29		—		38
2019
Acquisitions:
Proved	$	3	$	5	$	—	$	—	$	8
Unproved	47		10		—		—		57
Exploration	162		139		62		105		468
Development	1,500		374		119		3		1,996
Costs incurred(1)	$	1,712	$	528	$	181	$	108	$	2,529
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	23	$	—	$	5	$	4	$	32
Asset retirement costs	14		—		(111)		—		(97)
(2) Includes a noncontrolling interest in Egypt.

 In 2021, in connection with Apache’s agreement to enter into a modernized PSC agreement with EGPC, as referenced in Note 1—Summary of Significant Accounting Policies, the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments.

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions)
2021
Proved properties	$	18,732	$	12,373	$	8,954	$	—	$	40,059
Unproved properties	319		63		33		—		415
	19,051		12,436		8,987		—		40,474
Accumulated DD&A	(14,814)		(10,767)		(7,345)		—		(32,926)
	$	4,237	$	1,669	$	1,642	$	—	$	7,548
2020
Proved properties	$	20,343	$	12,069	$	8,805	$	—	$	41,217
Unproved properties	348		77		42		135		602
	20,691		12,146		8,847		135		41,819
Accumulated DD&A	(16,252)		(10,290)		(7,081)		—		(33,623)
	$	4,439	$	1,856	$	1,766	$	135	$	8,196

(1)Includes a noncontrolling interest in Egypt..

Oil and Gas Reserve Information

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.

	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	300,484	110,014	104,491	514,989
December 31, 2019	278,145	103,573	101,712	483,430
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
Proved undeveloped reserves:
December 31, 2018	45,182	9,484	11,278	65,944
December 31, 2019	46,716	10,831	10,049	67,596
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
Total proved reserves:
Balance December 31, 2018	345,666	119,498	115,769	580,933
Extensions, discoveries and other additions	52,297	21,039	9,017	82,353
Revisions of previous estimates	(16,446)	4,752	5,132	(6,562)
Production	(38,344)	(30,885)	(18,157)	(87,386)
Sales of minerals in-place	(18,312)	—	—	(18,312)
Balance December 31, 2019	324,861	114,404	111,761	551,026
Extensions, discoveries and other additions	17,858	17,855	5,275	40,988
Revisions of previous estimates	(69,247)	2,541	(4,756)	(71,462)
Production	(32,299)	(27,591)	(18,441)	(78,331)
Sales of minerals in-place	(8,721)	—	—	(8,721)
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615

(1)Includes proved reserves of 39 MMbbls, 36 MMbbls, 38 MMbbls, and 40 MMbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	197,574	502	1,938	200,014
December 31, 2019	158,794	667	2,317	161,778
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
Proved undeveloped reserves:
December 31, 2018	33,796	60	631	34,487
December 31, 2019	23,569	90	660	24,319
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
Total proved reserves:
Balance December 31, 2018	231,370	562	2,569	234,501
Extensions, discoveries and other additions	41,343	27	697	42,067
Revisions of previous estimates	(32,569)	508	345	(31,716)
Production	(24,959)	(340)	(634)	(25,933)
Sales of minerals in-place	(32,822)	—	—	(32,822)
Balance December 31, 2019	182,363	757	2,977	186,097
Extensions, discoveries and other additions	11,435	97	312	11,844
Revisions of previous estimates	(469)	264	(207)	(412)
Production	(27,133)	(276)	(709)	(28,118)
Sales of minerals in-place	(456)	—	—	(456)
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362

(1)  Includes proved reserves of 159 Mbbls, 281 Mbbls, 252 Mbbls, and 187 Mbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)
	(Millions of cubic feet)
Proved developed reserves:
December 31, 2018	1,626,403	476,132	95,347	2,197,882
December 31, 2019	945,938	433,382	106,329	1,485,649
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
Proved undeveloped reserves:
December 31, 2018	267,090	33,006	15,804	315,900
December 31, 2019	115,040	24,704	16,604	156,348
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
Total proved reserves:
Balance December 31, 2018	1,893,493	509,138	111,151	2,513,782
Extensions, discoveries and other additions	249,205	34,758	27,711	311,674
Revisions of previous estimates	(509,753)	18,570	4,015	(487,168)
Production	(233,447)	(104,380)	(19,944)	(357,771)
Sales of minerals in-place	(338,520)	—	—	(338,520)
Balance December 31, 2019	1,060,978	458,086	122,933	1,641,997
Extensions, discoveries and other additions	60,965	83,718	8,140	152,823
Revisions of previous estimates	215,166	(19,849)	(33,541)	161,776
Production	(205,594)	(100,348)	(21,032)	(326,974)
Sales of minerals in-place	(2,255)	—	—	(2,255)
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906

(1) Includes proved reserves of 158 Bcf, 141 Bcf, 153 Bcf, and 170 Bcf as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2018	769,125	189,871	122,320	1,081,316
December 31, 2019	594,595	176,470	121,751	892,816
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
Proved undeveloped reserves:
December 31, 2018	123,493	15,045	14,543	153,081
December 31, 2019	89,458	15,038	13,476	117,972
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
Total proved reserves:
Balance December 31, 2018	892,618	204,916	136,863	1,234,397
Extensions, discoveries and other additions	135,174	26,859	14,333	176,366
Revisions of previous estimates	(133,974)	8,355	6,146	(119,473)
Production	(102,211)	(48,622)	(22,115)	(172,948)
Sales of minerals in-place	(107,554)	—	—	(107,554)
Balance December 31, 2019	684,053	191,508	135,227	1,010,788
Extensions, discoveries and other additions	39,454	31,905	6,944	78,303
Revisions of previous estimates	(33,854)	(502)	(10,554)	(44,910)
Production	(93,698)	(44,592)	(22,655)	(160,945)
Sales of minerals in-place	(9,553)	—	—	(9,553)
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962

(1) Includes total proved reserves of 66 MMboe, 59 MMboe, 64 MMboe, and 68 MMboe as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.

As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.

During 2020, the Company added approximately 78 MMboe from extensions, discoveries, and other additions. The Company recorded 39 MMboe of exploration and development adds in the U.S., primarily in the Southern Midland Basin (26 MMboe) associated with the Wolfcamp and Spraberry drilling programs and the remainder in the Delaware Basin and Austin Chalk. The international operations contributed 39 MMboe of exploration and development adds during 2020, with Egypt contributing 32 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and Umbarka Area concessions. The North Sea contributed 7 MMboe from drilling success, primarily in the Beryl Field. The Company had combined downward revisions of previously estimated reserves of 45 MMboe. Downward revisions related to changes in product prices accounted for 70 MMboe, engineering and performance upward revisions accounted for 27 MMboe, and downward interest revisions accounted for 2 MMboe. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge.

During 2019, the Company added approximately 176 MMboe from extensions, discoveries, and other additions. The Company recorded 135 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Spraberry, Barnett, and Wolfcamp drilling programs in the Permian Basin (129 MMboe) and various offset drilling activity in the Midcontinent region (6 MMboe). The Company’s international assets contributed 41 MMboe of exploration and development adds during 2019. Egypt contributed 27 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, East Bahariya Extension 3, and West Kanayis concessions. The North Sea contributed 14 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 119 MMboe. Downward revisions related to changes in product prices accounted for 139 MMboe and engineering and performance upward revisions accounted for 20 MMboe. The Company also sold 107 MMboe of proved reserves associated with U.S. divestitures, primarily related to the sale of the Company’s Woodford-SCOOP and STACK plays and Western Anadarko Basin assets.

Approximately 12 percent of the Company’s year-end 2021 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2021, 2020, and 2019 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

	United States		Egypt(1)		North Sea		Total(1)
	(In millions)
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360
2020
Cash inflows	$	12,537	$	5,560	$	4,122	$	22,219
Production costs	(6,244)		(1,704)		(2,388)		(10,336)
Development costs	(1,555)		(633)		(2,448)		(4,636)
Income tax expense	—		(1,096)		316		(780)
Net cash flows	4,738		2,127		(398)		6,467
10 percent discount rate	(1,829)		(437)		1,111		(1,155)
Discounted future net cash flows(2)	$	2,909	$	1,690	$	713	$	5,312
2019
Cash inflows	$	21,694	$	8,306	$	7,454	$	37,454
Production costs	(10,642)		(1,847)		(2,730)		(15,219)
Development costs	(1,740)		(707)		(2,651)		(5,098)
Income tax expense	(27)		(1,930)		(784)		(2,741)
Net cash flows	9,285		3,822		1,289		14,396
10 percent discount rate	(4,003)		(808)		297		(4,514)
Discounted future net cash flows(2)	$	5,282	$	3,014	$	1,586	$	9,882

(1)Includes discounted future net cash flows of approximately $1.1 billion, $563 million, and $1.0 billion as of December 31, 2021, 2020, and 2019, respectively, attributable to a noncontrolling interest in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $15.3 billion, $7.1 billion, and $12.4 billion as of December 31, 2021, 2020, and 2019, respectively.

The following table sets forth the principal sources of change in the discounted future net cash flows:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Sales, net of production costs	$	(4,707)	$	(2,422)	$	(4,291)
Net change in prices and production costs	9,376		(5,753)		(3,034)
Discoveries and improved recovery, net of related costs	1,749		751		2,042
Change in future development costs	(839)		20		(75)
Previously estimated development costs incurred during the period	545		576		983
Revision of quantities	1,983		(418)		(741)
Purchases of minerals in-place	1		—		—
Accretion of discount	626		1,236		1,693
Change in income taxes	(1,583)		1,533		720
Sales of minerals in-place	(116)		(104)		(817)
Change in production rates and other	13		11		(319)
	$	7,048	$	(4,570)	$	(3,839)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

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

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. ALTM is consolidated and qualifies as a variable interest entity (VIE) under GAAP. Additionally, in November of 2021, the Company determined that a limited partnership and Apache subsidiary, which has control over Apache’s Egyptian operations, qualifies as a VIE under GAAP. Apache consolidates the activities of ALTM and Apache’s Egyptian operations because it has concluded that Apache’s subsidiaries have a controlling financial interest in ALTM and APA’s Egyptian operations, respectively, and were determined to be the primary beneficiaries of the VIEs. Additionally, the assets of ALTM may only be used to settle obligations of ALTM. There is no recourse to the Company for ALTM’s liabilities.

Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate 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. The Company regularly reassesses whether changes in the facts and circumstances regarding the Company’s involvement with a VIE could cause a change in its conclusions related to consolidation. Changes in consolidation status, if any, are applied prospectively.

On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 14—Redeemable Noncontrolling Interest — Altus for further detail.

Investments in which the Company holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company’s proportionate share of the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations.

Use of Estimates

Use of Estimates

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

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 3—Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 and Note 7—Equity Method Interests), the assessment of asset retirement obligations (refer to Note 9—Asset Retirement Obligation), the estimate of income taxes (refer to Note 11—Income Taxes), the estimation of the contingent liability representing Apache’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 12—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 19—Supplemental Oil and Gas Disclosures (Unaudited)).

Revenue Recognition

Revenue Recognition

Upstream

The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to Apache-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.

The Company’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

On December 27, 2021, the Company announced the ratification of a modernized PSC with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The Apache subsidiary that became the sole Contractor under the PSC is owned by an Apache-operated joint venture owned two-thirds by Apache and one-third by Sinopec.

Refer to Note 18—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Altus Midstream

The Company’s Altus Midstream segment is operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generates revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on Apache’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represents a single, distinct performance obligation on behalf of Altus that is satisfied over time. In accordance with the terms of these agreements, Altus primarily receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is primarily measured using the output method and recognized in the amount to which Altus has the right to invoice, as performance completed to date corresponds directly with the value to its customers. For the periods presented, Altus Midstream segment revenues were primarily attributable to sales between Altus and Apache, which are fully eliminated upon consolidation.

Payment Terms and Contract Balances

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, totaled $956 million and $670 million as of December 31, 2021 and 2020, respectively.

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.

Cash and Cash Equivalents

Cash and Cash EquivalentsThe Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value.

Accounts Receivable and Allowance for Credit Losses

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. The Company adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

Inventories

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.

Property and Equipment

Property and Equipment

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

Other Property and EquipmentOther property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years.

Oil and Gas Property

Oil and Gas Property

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

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

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

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

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

The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2019.

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Proved properties:
U.S.	$	—	$	3,938	$	1,484
Egypt	—		374		—
North Sea	—		7		—
Total proved properties	$	—	$	4,319	$	1,484
Unproved properties:
U.S.	$	22	$	92	$	760
Egypt	8		8		8
North Sea	1		1		—
Total unproved properties	$	31	$	101	$	768

Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively.

Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.

Gathering, Processing, and Transmission Facilities

Gathering, Processing, and Transmission Facilities

GPT facilities totaled $673 million and $670 million at December 31, 2021 and 2020, respectively, with accumulated depreciation for these assets totaling $386 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 Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity to those fields.

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

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

As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

Asset Retirement Costs and Obligations

Asset Retirement Costs and Obligations

The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Capitalized Interest

Capitalized InterestFor significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.

Goodwill

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense.

Equity Method Interests

Equity Method Interests

The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company.

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. In the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the announced BCP Business Combination, determined the current fair value of its investment in EPIC was below carrying value. Altus subsequently determined that this loss in value to be other than temporary. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in EPIC. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. Altus has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy.

Commitments and Contingencies

Commitments and ContingenciesAccruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.

All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations.

Income Taxes

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

Stock-Based Compensation

Stock-Based Compensation

Prior to consummation of the Holding Company Reorganization, Apache granted various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on APA’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s previous stock-based compensation plans, which were assumed by APA pursuant to the Holding Company Reorganization, and related accounting policies are defined and described more fully in Note 15—Capital Stock.

New Pronouncements Issued But Not Yet Adopted

New Pronouncements Issued But Not Yet Adopted

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by the discontinuation of the London Interbank Offered Rate (LIBOR) or by another reference rate expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarified the scope and application of the original guidance. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. The Company is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.

In August 2020, the FASB issued ASU 2020-06, “Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40)” to improve financial reporting associated with accounting for convertible instruments and contracts in an entity’s own equity. This update is effective for the Company beginning in the first quarter of 2022 using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company does not believe it will have a material impact on its financial statements.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Schedule of Asset Impairments Recorded in Connection with Fair Value Assessment

The following table presents a summary of asset impairments recorded in connection with fair value assessments:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil and gas proved property	$	—	$	4,319	$	1,484
Gathering, processing, and transmission facilities	—		68		1,295
Equity method interests	160		—		—
Divested unproved properties and leasehold	—		—		149
Goodwill	—		87		—
Inventory and other	48		27		21
Total Impairments	$	208	$	4,501	$	2,949

Schedule of Allowance for Doubtful Accounts

The following table presents changes to the Company’s allowance for credit loss:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Allowance for credit loss at beginning of year	$	95	$	88	$	92
Additional provisions for the year	19		7		3
Uncollectible accounts written off, net of recoveries	(5)		—		(7)
Allowance for credit loss at end of year	$	109	$	95	$	88

Schedule of Non-cash Impairments of Proved and Unproved Properties

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Proved properties:
U.S.	$	—	$	3,938	$	1,484
Egypt	—		374		—
North Sea	—		7		—
Total proved properties	$	—	$	4,319	$	1,484
Unproved properties:
U.S.	$	22	$	92	$	760
Egypt	8		8		8
North Sea	1		1		—
Total unproved properties	$	31	$	101	$	768

Schedule of Goodwill

The following presents the changes to goodwill for the years ended 2020 and 2019:

	Egypt		Total
	(In millions)
Goodwill at December 31, 2018	$	87	$	87
Impairments	—		—
Goodwill at December 31, 2019	87		87
Impairments	(87)		(87)
Goodwill at December 31, 2020	$	—	$	—

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CAPITALIZED EXPLORATORY WELL COSTS (Tables)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs, Roll Forward

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2021, 2020, and 2019. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Capitalized well costs at beginning of year	$	197	$	141	$	159
Additions pending determination of proved reserves	62		226		286
Divestitures and other	(163)		(38)		(100)
Reclassifications to proved properties	(40)		(56)		(179)
Charged to exploration expense	(10)		(76)		(25)
Capitalized well costs at end of year	$	46	$	197	$	141

Schedule of Aging of Capitalized Exploratory Well Costs

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:

	2021		2020		2019
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	13	$	184	$	108
Exploratory well costs capitalized for a period greater than one year	33		13		33
Capitalized well costs at end of year	$	46	$	197	$	141
Number of projects with exploratory well costs capitalized for a period greater than one year	9		5		2

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2021, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:

	Total		2020		2019		2018 and Prior
	(In millions)
Egypt	$	9	$	—	$	—	$	9
North Sea	24		24		—		—
	$	33	$	24	$	—	$	9

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 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
January—December 2022	NYMEX Henry Hub/IF Waha	43,800	$(0.45)	—	—
January—December 2022	NYMEX Henry Hub/IF HSC	—	—	43,800	$(0.08)
January—December 2023	NYMEX Henry Hub/IF Waha	29,200	$(0.40)	—	—
January—December 2023	NYMEX Henry Hub/IF HSC	—	—	29,200	$0.02

Schedule of Derivative Assets Measured at Fair Value

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2021
Liabilities:
Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Pipeline capacity embedded derivatives	—		46		—		46		—		46
Preferred Units embedded derivative	—		—		57		57		—		57
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivatives	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

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

Schedule of Derivative Liabilities Measured at Fair Value

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

	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
December 31, 2021
Liabilities:
Commodity derivative instruments	$	—	$	10	$	—	$	10	$	—	$	10
Pipeline capacity embedded derivatives	—		46		—		46		—		46
Preferred Units embedded derivative	—		—		57		57		—		57
December 31, 2020
Assets:
Commodity derivative instruments	$	—	$	11	$	—	$	11	$	—	$	11
Liabilities:
Pipeline capacity embedded derivatives	—		53		—		53		—		53
Preferred Units embedded derivative	—		—		139		139		—		139

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

Schedule of Fair Value Measurement Inputs

As of the December 31, 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 at December 31, 2021		Valuation Technique	Significant Unobservable Inputs	Range/Value
	(In millions)
Preferred Units embedded derivative	$	57	Option Model	Altus’ Imputed Interest Rate	5.54-11.21%
				Interest Rate Volatility	40.08%

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

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

	For the Year Ended December 31,
	2021		2020
	(In millions)
Current Assets: Other current assets	$	—	$	6
Other Assets: Deferred charges and other	—		5
Total derivative assets	$	—	$	11
Current Liabilities: Other current liabilities	$	4	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	109		192
Total derivative liabilities	$	113	$	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 Year Ended December 31,
	2021		2020		2019
	(In millions)
Realized:
Commodity derivative instruments	$	25	$	(135)	$	27
Foreign currency derivative instruments	—		(1)		—
Treasury-lock	—		—		(18)
Realized gain (loss), net	25		(136)		9
Unrealized:
Commodity derivative instruments	(20)		11		(44)
Pipeline capacity embedded derivatives	7		(61)		8
Foreign currency derivative instruments	—		(1)		1
Preferred Units embedded derivative	82		(36)		(9)
Unrealized gain (loss), net	69		(87)		(44)
Derivative instrument gains (losses), net	$	94	$	(223)	$	(35)

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OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2021

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

Schedule of Other Current Assets

The following table provides detail of the Company’s other current assets as of December 31:

	2021		2020
	(In millions)
Inventories	$	438	$	492
Drilling advances	55		113
Prepaid assets and other	56		71
Current decommissioning security for sold Gulf of Mexico assets	100		—
Total Other current assets	$	649	$	676

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EQUITY METHOD INTERESTS (Tables)

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Summary of Equity Method Investment Information

	Interest		2021		2020
			(In millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	274	$	284
EPIC Crude Holdings, LP	15.0	%	—		176
Permian Highway Pipeline LLC	26.7	%	630		615
Shin Oak Pipeline (Breviloba, LLC)	33.0	%	461		480
Total Altus equity method interests			$	1,365	$	1,555

The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2021 and 2020:

	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2019	$	291	$	163	$	311	$	493	$	1,258
Capital contributions	2		29		296		—		327
Distributions	(51)		—		—		(46)		(97)
Capitalized interest(1)	—		—		8		—		8
Equity income (loss), net	42		(16)		—		33		59
Balance at December 31, 2020	284		176		615		480		1,555
Capital contributions	—		2		26		—		28
Distributions	(50)		—		(74)		(49)		(173)
Equity income (loss), net	40		(19)		63		30		114
Accumulated other comprehensive loss	—		1		—		—		1
Impairment(2)	—		(160)		—		—		(160)
Balance at December 31, 2021	$	274	$	—	$	630	$	461	$	1,365

(1)Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million of related interest expense during 2020, which is included in the basis of the PHP equity interest.

(2)The Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies for further details on this impairment charge.

The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis):

	For the Year Ended December 31,
	2021		2020		2019(1)
	(In millions)
Operating revenues	$	1,082	$	707	$	302
Operating income	548		331		121
Net income	468		256		120
Other comprehensive income (loss)	4		3		(8)

(1)Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the full year ended December 31, 2019 for comparability.

The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31:

	2021		2020
	(In millions)
Current assets	$	280	$	260
Noncurrent assets	7,445		7,678
Total assets	$	7,725	$	7,938
Current liabilities	$	153	$	206
Noncurrent liabilities	1,193		1,191
Equity	6,379		6,541
Total liabilities and equity	$	7,725	$	7,938

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OTHER CURRENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities as of December 31:

	2021		2020
	(In millions)
Accrued operating expenses	$	129	$	91
Accrued exploration and development	206		167
Accrued compensation and benefits	292		170
Accrued interest	107		140
Accrued income taxes	28		25
Current asset retirement obligation	41		56
Current operating lease liability	99		116
Current decommissioning contingency for sold Gulf of Mexico properties	100		—
Other	168		97
Total Other current liabilities	$	1,170	$	862

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes to Asset Retirement Obligation

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

	For the Year Ended December 31,
	2021		2020
	(In millions)
Asset retirement obligation at beginning of the year	$	1,944	$	1,858
Liabilities incurred	3		10
Liabilities divested	(44)		(26)
Liabilities settled	(32)		(30)
Accretion expense	113		109
Revisions in estimated liabilities	146		23
Asset retirement obligation at end of the year	2,130		1,944
Less current portion	(41)		(56)
Asset retirement obligation, long-term	$	2,089	$	1,888

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DEBT AND FINANCING COSTS (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Debt

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

	December 31,
	2021		2020
	(In millions)
3.25% notes due 2022(1)(2)	$	213	$	213
2.625% notes due 2023(2)	123		123
4.625% notes due 2025(2)	500		500
7.7% notes due 2026	79		79
7.95% notes due 2026	133		133
4.875% due 2027(2)	378		750
4.375% notes due 2028(2)	703		993
7.75% notes due 2029(2)(3)	235		235
4.25% notes due 2030(2)	580		580
6.0% notes due 2037(2)	443		443
5.1% notes due 2040(2)	1,333		1,333
5.25% notes due 2042(2)	399		399
4.75% notes due 2043(2)	428		1,133
4.25% notes due 2044(2)	221		559
7.375% debentures due 2047	150		150
5.35% notes due 2049(2)	387		390
7.625% debentures due 2096	39		39
Notes and debentures before unamortized discount and debt issuance costs(4)	6,344		8,052
Commercial paper	—		—
Altus credit facility(5)	657		624
Apache credit facility(5)	542		150
Finance lease obligations	36		38
Unamortized discount	(30)		(35)
Debt issuance costs	(39)		(57)
Total debt	7,510		8,772
Current maturities	(215)		(2)
Long-term debt	$	7,295	$	8,770

(1)On January 18, 2022, Apache redeemed the 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.

(2)These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.

(3)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.

(4)The fair values of Apache’s notes and debentures were $7.1 billion and $8.5 billion as of December 31, 2021 and 2020, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

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

Schedule of Long Term Debt by Maturity

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2021 are as follows:

	(In millions)
2022	$	213
2023	123
2024	—
2025	500
2026	212
Thereafter	5,296
Notes and debentures, excluding discounts and debt issuance costs	$	6,344

Components of Financing Costs, Net

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

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Interest expense	$	419	$	438	$	430
Amortization of debt issuance costs	8		8		7
Capitalized interest	—		(12)		(37)
Loss (gain) on extinguishment of debt	104		(160)		75
Interest income	(8)		(7)		(13)
Interest income from APA Corporation, net	(51)		—		—
Financing costs, net	$	472	$	267	$	462

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income (Loss) Before Income Taxes

Income (loss) before income taxes is composed of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
U.S.	$	689	$	(4,581)	$	(4,397)
Foreign	1,291		(259)		1,389
Total	$	1,980	$	(4,840)	$	(3,008)

Total Provision for Income Taxes

The total income tax provision consists of the following:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Current income taxes:
Federal	$	16	$	(2)	$	1
Foreign	636		178		659
	652		176		660
Deferred income taxes:
Federal	—		—		67
Foreign	(74)		(112)		(53)
	(74)		(112)		14
Total	$	578	$	64	$	674

Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense

A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	416	$	(1,016)	$	(631)
State income tax, less federal effect(1)	—		—		1
Taxes related to foreign operations	300		97		328
Tax credits	(10)		(13)		(6)
Net change in tax contingencies	16		1		1
Goodwill impairment	—		35		—
Valuation allowances(1)	(111)		965		972
Tax attributable to Altus Preferred Unit limited partners	(34)		(16)		(8)
All other, net	1		11		17
	$	578	$	64	$	674

(1)The change in state valuation allowance is included as a component of state income tax.

Net Deferred Tax Liability

The net deferred income tax liability consists of the following as of December 31:

	2021		2020
	(In millions)
Deferred tax assets:
U.S. and state net operating losses	$	2,494	$	2,306
Capital losses	647		633
Tax credits and other tax incentives	24		33
Foreign tax credits	2,241		2,241
Accrued expenses and liabilities	152		93
Asset retirement obligation	712		654
Property and equipment	3		261
Investment in Altus Midstream LP	64		76
Net interest expense limitation	135		252
Lease liability	81		79
Decommissioning contingency for sold Gulf of Mexico properties	263		—
Other	1		1
Total deferred tax assets	6,817		6,629
Valuation allowance	(5,875)		(5,991)
Net deferred tax assets	942		638
Deferred tax liabilities:
Equity investments	2		4
Property and equipment	748		750
Right-of-use asset	77		74
Decommissioning security for sold Gulf of Mexico properties	164		—
Other	86		13
Total deferred tax liabilities	1,077		841
Net deferred income tax liability	$	135	$	203

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:

	2021		2020
	(In millions)
Assets:
Deferred charges and other	$	13	$	12
Liabilities:
Income taxes	148		215
Net deferred income tax liability	$	135	$	203

Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	5,991	$	4,959	$	3,947
State(1)	1		67		41
U.S.	(112)		960		971
Foreign	(5)		5		—
Balance at end of year	$	5,875	$	5,991	$	4,959

(1)Reported as a component of state income taxes.

Net Operating Losses

On December 31, 2021, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
U.S.	$	9,717	2021 - Indefinite
State	6,695		Various
Foreign	1		2028 - Indefinite

Schedule of Foreign Tax Credit Carryforward

On December 31, 2021, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,241	2025-2026

Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2021		2020		2019
	(In millions)
Balance at beginning of year	$	93	$	82	$	24
Additions based on tax positions related to prior year	16		—		49
Additions based on tax positions related to the current year	7		11		9
Balance at end of year	$	116	$	93	$	82

Key Jurisdictions of Company's Earliest Open Tax Years

Apache’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction

U.S.	2014
Egypt	2005
U.K.	2020

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Lease Cost

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2021:

	Operating Leases		Finance Leases
Weighted average remaining lease term	3.4 years		11.7 years
Weighted average discount rate	3.7	%	4.4	%

Operating Lease, Liability, Maturity

At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)	Operating Leases(2)		Finance Leases(3)		Purchase Obligations(4)(5)
	(In millions)
2022	$	106	$	3	$	230
2023	75		3		199
2024	58		3		161
2025	7		4		159
2026	7		4		3,637
Thereafter	18		25		463
Total future minimum payments	271		42		$	4,849
Less: imputed interest	(22)		(6)		N/A
Total lease liabilities	249		36		N/A
Current portion	99		2		N/A
Non-current portion	$	150	$	34	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $194 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.

(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

Finance Lease, Liability, Maturity

At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)	Operating Leases(2)		Finance Leases(3)		Purchase Obligations(4)(5)
	(In millions)
2022	$	106	$	3	$	230
2023	75		3		199
2024	58		3		161
2025	7		4		159
2026	7		4		3,637
Thereafter	18		25		463
Total future minimum payments	271		42		$	4,849
Less: imputed interest	(22)		(6)		N/A
Total lease liabilities	249		36		N/A
Current portion	99		2		N/A
Non-current portion	$	150	$	34	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $194 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.

(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

Long-term Purchase Commitment

At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)	Operating Leases(2)		Finance Leases(3)		Purchase Obligations(4)(5)
	(In millions)
2022	$	106	$	3	$	230
2023	75		3		199
2024	58		3		161
2025	7		4		159
2026	7		4		3,637
Thereafter	18		25		463
Total future minimum payments	271		42		$	4,849
Less: imputed interest	(22)		(6)		N/A
Total lease liabilities	249		36		N/A
Current portion	99		2		N/A
Non-current portion	$	150	$	34	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $194 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.

(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

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RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2021, 2020, and 2019, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	233		$	20		$	199		$	20		$	187		$	27
Service cost	3			1			3			1			3			2
Interest cost	3			—			4			—			5			1
Foreign currency exchange rates	(2)			—			8			—			7			—
Actuarial losses (gains)	(5)			1			30			1			15			(9)
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Projected benefit obligation at end of year	211			20			233			20			199			20
Change in Plan Assets
Fair value of plan assets at beginning of year	262			—			228			—			208			—
Actual return on plan assets	11			—			31			—			25			—
Foreign currency exchange rates	(3)			—			9			—			8			—
Employer contributions	5			2			5			2			5			1
Plan settlements	(17)			—			—			—			(14)			—
Benefits paid	(4)			(4)			(11)			(4)			(4)			(2)
Retiree contributions	—			2			—			2			—			1
Fair value of plan assets at end of year	254			—			262			—			228			—
Funded status at end of year	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	43			(18)			29			(18)			29			(18)
	$	43		$	(20)		$	29		$	(20)		$	29		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	1		$	14		$	(11)		$	16		$	(7)		$	19
Weighted Average Assumptions used as of December 31
Discount rate	1.80		%	2.57		%	1.40		%	2.06		%	2.10		%	3.00		%
Salary increases	4.90		%	N/A			4.50		%	N/A			4.30		%	N/A
Expected return on assets	1.90		%	N/A			1.50		%	N/A			2.20		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.00		%	N/A			6.25		%
Ultimate in 2028	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset

A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:

	Target Allocation		Percentage of Plan Assets at Year-End
	2021		2021		2020
Asset Category
Equity securities:
Overseas quoted equities	15	%	15	%	19	%
Total equity securities	15	%	15	%	19	%
Debt securities:
U.K. government bonds	55	%	54	%	64	%
U.K. corporate bonds	24	%	25	%	16	%
Total debt securities	79	%	79	%	80	%
Cash	6	%	6	%	1	%
Total	100	%	100	%	100	%

Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets

The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2021 and 2020:

	December 31,
	2021		2020
	(In millions)
Equity securities:
Overseas quoted equities	$	38	$	49
Total equity securities	38		49
Debt securities:
U.K. government bonds	138		168
U.K. corporate bonds	62		43
Total debt securities	200		211
Cash	16		2
Fair value of plan assets	$	254	$	262

Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2021, 2020, and 2019: 

	2021						2020						2019
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	3		$	1		$	3		$	1		$	3		$	2
Interest cost	3			—			4			—			5			1
Expected return on assets	(4)			—			(5)			—			(5)			—
Amortization of loss	—			(1)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	2		$	—		$	2		$	—		$	3		$	2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	1.40		%	2.06		%	2.10		%	3.00		%	2.90		%	4.13		%
Salary increases	4.50		%	N/A			4.30		%	N/A			4.70		%	N/A
Expected return on assets	1.50		%	N/A			2.20		%	N/A			2.80		%	N/A
Healthcare cost trend
Initial	N/A			6.00		%	N/A			6.25		%	N/A			6.50		%
Ultimate in 2025	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

Expected Future Benefit Payment

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2022	$	6	$	2
2023	7		2
2024	6		2
2025	6		2
2026	6		2
Years 2027-2031	39		6

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REDEMABLE NONCONTROLLING INTEREST - ALTUS (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Schedule of Preferred Units

The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:

	June 12, 2019
	(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$	517
Preferred Units embedded derivative	94
	$	611

Activity related to the Preferred Units for the years ended December 31, 2021 and 2020 is as follows:

	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units: at December 31, 2019	638,163	$	555
Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions paid to Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream net income	N/A	76
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020	660,694	608
Cash distributions to Altus Preferred Unit limited partners	—	(46)
Distributions payable to Altus Preferred Unit limited partners	—	(12)
Allocation of Altus Midstream LP net income	N/A	80
Accreted value adjustment	N/A	82
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2021	660,694	712
Preferred Units embedded derivative(2)		57
		$	769

(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of December 31, 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 December 31, 2021, the Redemption Price would have been based on an 11.5 percent internal rate of return, which would equate to a redemption value of $739 million.

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

N/A - not applicable.

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CAPITAL STOCK AND EQUITY (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Common Stock Outstanding

Description of Stock Based Compensation Plans and Related Costs

The following table summarizes the Company’s stock-settled and cash-settled compensation costs:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Stock-settled and cash-settled compensation expensed	$	152	$	40	$	110
Stock-settled and cash-settled compensation capitalized	18		7		28
Total stock-settled and cash-settled compensation costs	$	170	$	47	$	138

Summary of Stock Options Activities

The following table summarizes stock option activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price		Shares Under Option	Weighted  Average Exercise Price
	(In thousands, except exercise price amounts)
Outstanding, beginning of year	3,537	$	72.10	4,298	$	75.24	4,872	$	75.95
Forfeited	—	—		(37)	44.98		(80)	34.58
Expired	(525)	119.83		(724)	92.14		(494)	88.82
Outstanding, end of year(1)	3,012	63.79		3,537	72.10		4,298	75.24
Expected to vest	—	—		150	45.77		495	49.11
Exercisable, end of year(2)	3,012	63.79		3,387	73.26		3,803	78.64

(1)As of December 31, 2021, options outstanding had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

(2)As of December 31, 2021, options exercisable had a weighted average remaining contractual life of 3.1 years and no intrinsic value.

Schedule of Restricted Stock and Restricted Stock Units Activity

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2021, 2020, and 2019:

	2021			2020			2019
	Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value		Units	Weighted Average  Grant-Date  Fair Value
	(In thousands, except per share amounts)
Non-vested, beginning of year	1,552	$	28.43	2,448	$	46.65	3,153	$	55.54
Granted	1,506	16.46		1,352	24.60		1,479	36.81
Vested(3)	(857)	29.13		(1,933)	48.65		(1,899)	53.99
Forfeited	(128)	19.78		(315)	30.09		(285)	45.06
Non-vested, end of year(1)(2)	2,073	19.98		1,552	28.43		2,448	46.65

(1)As of December 31, 2021, there was $14 million of total unrecognized compensation cost related to 2,073,419 unvested stock-settled restricted stock units.

(2)As of December 31, 2021, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2021, 2020, and 2019 were approximately $25 million, $94 million, and $103 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2021, 2020, and 2019:

	For the Year Ended December 31,
	2021	2020	2019
	(In thousands)
Non-vested, beginning of year	4,423	5,384	1,818
Adjustment for ALTM reverse stock split(1)	—	(1,246)	—
Granted(2)	4,441	3,462	4,831
Vested	(2,049)	(1,618)	(616)
Forfeited	(413)	(1,559)	(649)
Non-vested, end of year(3)	6,402	4,423	5,384

(1)On June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock.

(2)Restricted stock phantom units granted during 2021 and 2020 included 4,375,546 and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 65,327 and 83,239 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2021 was approximately $74 million.

The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2021:

	Units
	(In thousands)
Non-vested, beginning of year	3,417
Granted	1,782
Vested	(76)
Forfeited	(240)
Expired	(352)
Non-vested, end of year(1)	4,531

(1)As of December 31, 2021, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $36 million.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Components of Accumulated Other Comprehensive Income (Loss)

Components of accumulated other comprehensive income (loss) include the following:

	As of December 31,
	2021		2020		2019
	(In millions)
Share of equity method interests other comprehensive loss	$	—	$	(1)	$	(1)
Pension and postretirement benefit plan (Note 13)	22		15		17
Accumulated other comprehensive income	$	22	$	14	$	16

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BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each segment is presented below:

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration	63		34		28		—		2		127
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(128)		5,097
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(2)	2,888
Other Income (Expense):
Gain on divestitures, net											67
Loss on previously sold Gulf of Mexico properties											(446)
Derivative instrument gain, net											94
Other											228
General and administrative											(357)
Transaction, reorganization, and separation											(22)
Financing costs, net											(472)
Income Before Income Taxes											$	1,980
Total Assets(3)	$	2,796	$	2,199	$	7,700	$	1,698	$	—	$	14,393
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	—	$	8,060
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	—	$	1,004

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2020
Oil revenues	$	1,102	$	795	$	1,209	$	—	$	—	$	3,106
Natural gas revenues	280		67		251		—		—		598
Natural gas liquids revenues	8		21		304		—		—		333
Oil, natural gas, and natural gas liquids production revenues	1,390		883		1,764		—		—		4,037
Purchased oil and gas sales	—		—		394		4		—		398
Midstream service affiliate revenues	—		—		—		145		(145)		—
	1,390		883		2,158		149		(145)		4,435
Operating Expenses:
Lease operating expenses	424		305		400		—		(2)		1,127
Gathering, processing, and transmission	38		50		291		38		(143)		274
Purchased oil and gas costs	—		—		354		3		—		357
Taxes other than income	—		—		108		15		—		123
Exploration	63		28		168		—		15		274
Depreciation, depletion, and amortization	601		380		779		12		—		1,772
Asset retirement obligation accretion	—		73		32		4		—		109
Impairments	529		7		3,963		2		—		4,501
	1,655		843		6,095		74		(130)		8,537
Operating Income (Loss)	$	(265)	$	40	$	(3,937)	$	75	$	(15)	(4,102)
Other Income (Expense):
Gain on divestitures, net											32
Derivative instrument losses, net											(223)
Other											64
General and administrative											(290)
Transaction, reorganization, and separation											(54)
Financing costs, net											(267)
Loss Before Income Taxes											$	(4,840)
Total Assets(3)	$	3,003	$	2,220	$	5,540	$	1,786	$	197	$	12,746
Net Property and Equipment	$	1,955	$	1,773	$	4,760	$	196	$	135	$	8,819
Additions to Net Property and Equipment	$	454	$	215	$	345	$	12	$	136	$	1,162

	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream
	(In millions)
2019
Oil revenues	$	1,969	$	1,163	$	2,098	$	—	$	—	$	5,230
Natural gas revenues	295		90		293		—		—		678
Natural gas liquids revenues	12		23		372		—		—		407
Oil, natural gas, and natural gas liquids production revenues	2,276		1,276		2,763		—		—		6,315
Purchased oil and gas sales	—		—		176		—		—		176
Midstream service affiliate revenues	—		—		—		136		(136)		—
	2,276		1,276		2,939		136		(136)		6,491
Operating Expenses:
Lease operating expenses	484		320		645		—		(2)		1,447
Gathering, processing, and transmission	40		45		299		56		(134)		306
Purchased oil and gas costs	—		—		142		—		—		142
Taxes other than income	—		—		194		13		—		207
Exploration	100		2		688		—		15		805
Depreciation, depletion, and amortization	708		366		1,566		40		—		2,680
Asset retirement obligation accretion	—		76		29		2		—		107
Impairments	—		—		1,648		1,301		—		2,949
	1,332		809		5,211		1,412		(121)		8,643
Operating Income (Loss)	$	944	$	467	$	(2,272)	$	(1,276)	$	(15)	(2,152)
Other Income (Expense):
Gain on divestitures, net											43
Derivative instrument losses, net											(35)
Other											54
General and administrative											(406)
Transaction, reorganization, and separation											(50)
Financing costs, net											(462)
Loss Before Income Taxes											$	(3,008)
Total Assets(3)	$	3,700	$	2,473	$	10,388	$	1,479	$	67	$	18,107
Net Property and Equipment	$	2,573	$	1,956	$	9,385	$	206	$	38	$	14,158
Additions to Net Property and Equipment	$	454	$	183	$	1,696	$	308	$	93	$	2,734

(1)Includes revenue from non-customers for the years ended December 31, 2021, 2020, and 2019 of:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Oil	$	420	$	95	$	410
Natural gas	47		14		40
Natural gas liquids	2		—		1

(2)Includes a noncontrolling interest in Egypt and Altus Midstream.

(3)Intercompany balances are excluded from total assets.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions, except per boe)
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		2		127
Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		2		4,278
Results of operations	$	1,440	$	585	$	200	$	(2)	$	2,223
2020
Oil and gas production revenues	$	1,764	$	1,390	$	883	$	—	$	4,037
Operating cost:
Depreciation, depletion, and amortization(2)	726		540		377		—		1,643
Asset retirement obligation accretion	32		—		73		—		105
Lease operating expenses	400		424		305		—		1,129
Gathering, processing, and transmission	291		38		50		—		379
Exploration expenses	168		63		28		15		274
Impairments related to oil and gas properties	3,938		374		7		—		4,319
Production taxes(3)	106		—		—		—		106
Income tax	(818)		(22)		17		—		(823)
	4,843		1,417		857		15		7,132
Results of operations	$	(3,079)	$	(27)	$	26	$	(15)	$	(3,095)
2019
Oil and gas production revenues	$	2,763	$	2,276	$	1,276	$	—	$	6,315
Operating cost:
Depreciation, depletion, and amortization(2)	1,508		641		363		—		2,512
Asset retirement obligation accretion	29		—		76		—		105
Lease operating expenses	645		484		320		—		1,449
Gathering, processing, and transmission	299		40		45		—		384
Exploration expenses	688		100		2		15		805
Impairments related to oil and gas properties	1,633		—		—		—		1,633
Production taxes(3)	191		—		—		—		191
Income tax	(468)		455		188		—		175
	4,525		1,720		994		15		7,254
Results of operations	$	(1,762)	$	556	$	282	$	(15)	$	(939)

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 18—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 18—Business Segment Information.

Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities

	United States		Egypt(2)		North Sea		Other International		Total(2)
	(In millions)
2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		30		161
Development	545		404		135		1		1,085
Costs incurred(1)	$	560	$	353	$	174	$	31	$	1,118
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	—	$	—
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts - Proved and Unproved	—		(145)		—		—		(145)
2020
Acquisitions:
Proved	$	—	$	7	$	—	$	—	$	7
Unproved	4		—		—		—		4
Exploration	8		102		68		150		328
Development	332		378		162		—		872
Costs incurred(1)	$	344	$	487	$	230	$	150	$	1,211
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—	$	—	$	—	$	3	$	3
Asset retirement costs	9		—		29		—		38
2019
Acquisitions:
Proved	$	3	$	5	$	—	$	—	$	8
Unproved	47		10		—		—		57
Exploration	162		139		62		105		468
Development	1,500		374		119		3		1,996
Costs incurred(1)	$	1,712	$	528	$	181	$	108	$	2,529
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	23	$	—	$	5	$	4	$	32
Asset retirement costs	14		—		(111)		—		(97)
(2) Includes a noncontrolling interest in Egypt.

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:

	United States		Egypt(1)		North Sea		Other International		Total(1)
	(In millions)
2021
Proved properties	$	18,732	$	12,373	$	8,954	$	—	$	40,059
Unproved properties	319		63		33		—		415
	19,051		12,436		8,987		—		40,474
Accumulated DD&A	(14,814)		(10,767)		(7,345)		—		(32,926)
	$	4,237	$	1,669	$	1,642	$	—	$	7,548
2020
Proved properties	$	20,343	$	12,069	$	8,805	$	—	$	41,217
Unproved properties	348		77		42		135		602
	20,691		12,146		8,847		135		41,819
Accumulated DD&A	(16,252)		(10,290)		(7,081)		—		(33,623)
	$	4,439	$	1,856	$	1,766	$	135	$	8,196

(1)Includes a noncontrolling interest in Egypt..

Proved Reserve Data

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.

	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	300,484	110,014	104,491	514,989
December 31, 2019	278,145	103,573	101,712	483,430
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
Proved undeveloped reserves:
December 31, 2018	45,182	9,484	11,278	65,944
December 31, 2019	46,716	10,831	10,049	67,596
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
Total proved reserves:
Balance December 31, 2018	345,666	119,498	115,769	580,933
Extensions, discoveries and other additions	52,297	21,039	9,017	82,353
Revisions of previous estimates	(16,446)	4,752	5,132	(6,562)
Production	(38,344)	(30,885)	(18,157)	(87,386)
Sales of minerals in-place	(18,312)	—	—	(18,312)
Balance December 31, 2019	324,861	114,404	111,761	551,026
Extensions, discoveries and other additions	17,858	17,855	5,275	40,988
Revisions of previous estimates	(69,247)	2,541	(4,756)	(71,462)
Production	(32,299)	(27,591)	(18,441)	(78,331)
Sales of minerals in-place	(8,721)	—	—	(8,721)
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615

(1)Includes proved reserves of 39 MMbbls, 36 MMbbls, 38 MMbbls, and 40 MMbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands of barrels)
Proved developed reserves:
December 31, 2018	197,574	502	1,938	200,014
December 31, 2019	158,794	667	2,317	161,778
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
Proved undeveloped reserves:
December 31, 2018	33,796	60	631	34,487
December 31, 2019	23,569	90	660	24,319
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
Total proved reserves:
Balance December 31, 2018	231,370	562	2,569	234,501
Extensions, discoveries and other additions	41,343	27	697	42,067
Revisions of previous estimates	(32,569)	508	345	(31,716)
Production	(24,959)	(340)	(634)	(25,933)
Sales of minerals in-place	(32,822)	—	—	(32,822)
Balance December 31, 2019	182,363	757	2,977	186,097
Extensions, discoveries and other additions	11,435	97	312	11,844
Revisions of previous estimates	(469)	264	(207)	(412)
Production	(27,133)	(276)	(709)	(28,118)
Sales of minerals in-place	(456)	—	—	(456)
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362

(1)  Includes proved reserves of 159 Mbbls, 281 Mbbls, 252 Mbbls, and 187 Mbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)
	(Millions of cubic feet)
Proved developed reserves:
December 31, 2018	1,626,403	476,132	95,347	2,197,882
December 31, 2019	945,938	433,382	106,329	1,485,649
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
Proved undeveloped reserves:
December 31, 2018	267,090	33,006	15,804	315,900
December 31, 2019	115,040	24,704	16,604	156,348
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
Total proved reserves:
Balance December 31, 2018	1,893,493	509,138	111,151	2,513,782
Extensions, discoveries and other additions	249,205	34,758	27,711	311,674
Revisions of previous estimates	(509,753)	18,570	4,015	(487,168)
Production	(233,447)	(104,380)	(19,944)	(357,771)
Sales of minerals in-place	(338,520)	—	—	(338,520)
Balance December 31, 2019	1,060,978	458,086	122,933	1,641,997
Extensions, discoveries and other additions	60,965	83,718	8,140	152,823
Revisions of previous estimates	215,166	(19,849)	(33,541)	161,776
Production	(205,594)	(100,348)	(21,032)	(326,974)
Sales of minerals in-place	(2,255)	—	—	(2,255)
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906

(1) Includes proved reserves of 158 Bcf, 141 Bcf, 153 Bcf, and 170 Bcf as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)
	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2018	769,125	189,871	122,320	1,081,316
December 31, 2019	594,595	176,470	121,751	892,816
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
Proved undeveloped reserves:
December 31, 2018	123,493	15,045	14,543	153,081
December 31, 2019	89,458	15,038	13,476	117,972
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
Total proved reserves:
Balance December 31, 2018	892,618	204,916	136,863	1,234,397
Extensions, discoveries and other additions	135,174	26,859	14,333	176,366
Revisions of previous estimates	(133,974)	8,355	6,146	(119,473)
Production	(102,211)	(48,622)	(22,115)	(172,948)
Sales of minerals in-place	(107,554)	—	—	(107,554)
Balance December 31, 2019	684,053	191,508	135,227	1,010,788
Extensions, discoveries and other additions	39,454	31,905	6,944	78,303
Revisions of previous estimates	(33,854)	(502)	(10,554)	(44,910)
Production	(93,698)	(44,592)	(22,655)	(160,945)
Sales of minerals in-place	(9,553)	—	—	(9,553)
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962

(1) Includes total proved reserves of 66 MMboe, 59 MMboe, 64 MMboe, and 68 MMboe as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.

Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

	United States		Egypt(1)		North Sea		Total(1)
	(In millions)
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360
2020
Cash inflows	$	12,537	$	5,560	$	4,122	$	22,219
Production costs	(6,244)		(1,704)		(2,388)		(10,336)
Development costs	(1,555)		(633)		(2,448)		(4,636)
Income tax expense	—		(1,096)		316		(780)
Net cash flows	4,738		2,127		(398)		6,467
10 percent discount rate	(1,829)		(437)		1,111		(1,155)
Discounted future net cash flows(2)	$	2,909	$	1,690	$	713	$	5,312
2019
Cash inflows	$	21,694	$	8,306	$	7,454	$	37,454
Production costs	(10,642)		(1,847)		(2,730)		(15,219)
Development costs	(1,740)		(707)		(2,651)		(5,098)
Income tax expense	(27)		(1,930)		(784)		(2,741)
Net cash flows	9,285		3,822		1,289		14,396
10 percent discount rate	(4,003)		(808)		297		(4,514)
Discounted future net cash flows(2)	$	5,282	$	3,014	$	1,586	$	9,882

(1)Includes discounted future net cash flows of approximately $1.1 billion, $563 million, and $1.0 billion as of December 31, 2021, 2020, and 2019, respectively, attributable to a noncontrolling interest in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $15.3 billion, $7.1 billion, and $12.4 billion as of December 31, 2021, 2020, and 2019, respectively.

Principal Sources of Change In Discounted Future Net Cash Flows

The following table sets forth the principal sources of change in the discounted future net cash flows:

	For the Year Ended December 31,
	2021		2020		2019
	(In millions)
Sales, net of production costs	$	(4,707)	$	(2,422)	$	(4,291)
Net change in prices and production costs	9,376		(5,753)		(3,034)
Discoveries and improved recovery, net of related costs	1,749		751		2,042
Change in future development costs	(839)		20		(75)
Previously estimated development costs incurred during the period	545		576		983
Revision of quantities	1,983		(418)		(741)
Purchases of minerals in-place	1		—		—
Accretion of discount	626		1,236		1,693
Change in income taxes	(1,583)		1,533		720
Sales of minerals in-place	(116)		(104)		(817)
Change in production rates and other	13		11		(319)
	$	7,048	$	(4,570)	$	(3,839)

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NATURE OF OPERATIONS (Details)	12 Months Ended
	Dec. 31, 2021 Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)		3 Months Ended				9 Months Ended	12 Months Ended
	Dec. 27, 2021	Dec. 31, 2021	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments					$ 1,400,000,000		$ 208,000,000	$ 4,501,000,000	$ 2,949,000,000
Equity method investment impairment		$ 160,000,000					160,000,000	0	0
Inventory and other							48,000,000	27,000,000	21,000,000
Impairments							208,000,000	4,501,000,000	2,949,000,000
Goodwill impairment							0	87,000,000	0
Impairment for early termination of drilling rig leases						$ 13,000,000
Inventory write-downs			$ 5,000,000
Other asset impairments			$ 9,000,000
Receivables from contracts with customers, net of allowance for doubtful accounts		956,000,000				670,000,000	956,000,000	670,000,000
PSC, percentage of gross acreage consolidated	98.00%
PSC, percentage of gross production consolidated	90.00%
PSC, development lease term	20 years
PSC, exploration lease term	5 years
PSC, cost recovery limit	40.00%
PSC, fixed profit-sharing rate	30.00%
Cash and cash equivalent		279,000,000				262,000,000	279,000,000	262,000,000
Restricted cash		0				0	0	0
Oil and gas property impaired, fair value					$ 628,000,000	1,900,000,000		1,900,000,000	628,000,000
Divested unproved properties and leasehold							0	0	149,000,000
Gathering, processing, and transmission facilities ($209 and $206 related to Altus VIE)		673,000,000				670,000,000	673,000,000	670,000,000
GPT facilities, accumulated depreciation		386,000,000				323,000,000	386,000,000	323,000,000
Other property and equipment		1,126,000,000				1,140,000,000	1,126,000,000	1,140,000,000
Other property and equipment, accumulated depreciation		(901,000,000)				(864,000,000)	(901,000,000)	(864,000,000)
Restructuring cumulative cost incurred to date						79,000,000		79,000,000
Transaction, reorganization, and separation							22,000,000	54,000,000	50,000,000
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment								87,000,000	0
Employee Severance
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation							6,000,000	51,000,000	26,000,000
Consulting and Legal Fees
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation							11,000,000	2,000,000	2,000,000
Office closure
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation							5,000,000	1,000,000
Employee Termination and Office Closures
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation									15,000,000
Other restructuring
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation									7,000,000
Consulting And Separation Activities
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation							17,000,000
Alpine High Play
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impaired, fair value						203,000,000		203,000,000
Egypt
Schedule Of Significant Accounting Policies [Line Items]
Inventory and other							26,000,000
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Inventory and other							22,000,000
Oklahoma And Texas
Schedule Of Significant Accounting Policies [Line Items]
Impairment of assets to be disposed of									255,000,000
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments							0	4,319,000,000	1,484,000,000
Tangible asset impairment charges						20,000,000	0	4,319,000,000	$ 1,484,000,000
Oil and gas proved property | Significant Unobservable Inputs (Level 3) | Measurement Input, Discount Rate
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas properties, measurement inputs					10.00%				10.00%
Oil and gas proved property | United States
Schedule Of Significant Accounting Policies [Line Items]
Impairments				$ 3,900,000,000			0	3,938,000,000	$ 1,484,000,000
Oil and gas proved property | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments				354,000,000			0	374,000,000	0
Oil and gas proved property | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments				7,000,000			0	7,000,000	0
Oil and gas proved property | Oklahoma And Texas
Schedule Of Significant Accounting Policies [Line Items]
Impairment of assets to be disposed of									101,000,000
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Oil and gas property impaired, fair value				$ 46,000,000
Tangible asset impairment charges							0	68,000,000	1,295,000,000
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments							31,000,000	101,000,000	768,000,000
Oil and Gas Properties, Unproved | United States
Schedule Of Significant Accounting Policies [Line Items]
Impairments							22,000,000	92,000,000	760,000,000
Oil and Gas Properties, Unproved | Egypt
Schedule Of Significant Accounting Policies [Line Items]
Impairments							8,000,000	8,000,000	8,000,000
Oil and Gas Properties, Unproved | North Sea
Schedule Of Significant Accounting Policies [Line Items]
Impairments							$ 1,000,000	1,000,000	0
Oil and Gas Properties, Unproved | Oklahoma And Texas
Schedule Of Significant Accounting Policies [Line Items]
Impairment of assets to be disposed of									149,000,000
Divested unproved properties and leasehold									149,000,000
Other Working Capital | Oklahoma And Texas
Schedule Of Significant Accounting Policies [Line Items]
Impairment of assets to be disposed of									$ 5,000,000
Other Property and Equipment | Minimum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities							3 years
Other Property and Equipment | Maximum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities							20 years
ALTM
Schedule Of Significant Accounting Policies [Line Items]
Cash and cash equivalent		$ 132,000,000				$ 24,000,000	$ 132,000,000	$ 24,000,000
ALTM | Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Impairments					$ 1,300,000,000
Apache Egypt
Schedule Of Significant Accounting Policies [Line Items]
Noncontrolling interest, ownership percentage by parent	66.67%
Apache Egypt | Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage		33.33%					33.33%
ALTM | Third-party investors
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage		21.00%					21.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Impairments Recorded in Connection with Fair Value Assessments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Significant Accounting Policies [Line Items]
Equity method interests	$ 160			$ 160	$ 0	$ 0
Divested unproved properties and leasehold				0	0	149
Goodwill				0	87	0
Inventory and other				48	27	21
Impairments		$ 1,400		208	4,501	2,949
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges			$ 20	0	4,319	1,484
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment charges				$ 0	$ 68	$ 1,295

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Allowance for Credit Loss Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 95	$ 88	$ 92
Accounts receivable, credit loss expense (reversal)	19	7	3
Accounts receivable, allowance for credit loss, write-offs, net of recoveries	(5)	0	(7)
Allowance for credit loss at end of year	$ 109	$ 95	$ 88

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Non-Cash Impairments of Proved and Unproved Property and Equipment (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 208	$ 4,501	$ 2,949
Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	4,319	1,484
Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments		31	101	768
U.S. | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 3,900	0	3,938	1,484
U.S. | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments		22	92	760
Egypt | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments	354	0	374	0
Egypt | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments		8	8	8
North Sea | Oil and gas proved property
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 7	0	7	0
North Sea | Oil and Gas Properties, Unproved
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 1	$ 1	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Changes to Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 0	$ 87	$ 87
Impairments	0	(87)	0
Goodwill, ending balance		0	87
Egypt
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 0	87	87
Impairments		(87)	0
Goodwill, ending balance		$ 0	$ 87

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TRANSACTIONS WITH PARENT AFFILIATE (Details) $ in Millions			12 Months Ended
	Aug. 04, 2021 USD ($)	Mar. 01, 2021 USD ($) subsidiary	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Related Party Transaction [Line Items]
Interest income from APA Corporation, net			$ (51)	$ 0	$ 0
Reimbursable costs charged to Parent			$ 17
Affiliated Entity | Promissory Note
Related Party Transaction [Line Items]
Debt face amount	$ 250
Debt term	1 year
Holding Company Reorganization | Affiliated Entity
Related Party Transaction [Line Items]
Number of subsidiaries | subsidiary		3
Note receivable, term		7 years
Note receivable, interest rate		4.50%
Note receivable, accrued interest converted to principal, term		5 years 6 months
Holding Company Reorganization | Affiliated Entity | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Three Apache Subsidiaries
Related Party Transaction [Line Items]
Net assets transferred		$ 483
Cash and cash equivalents transferred		292
Oil and gas properties, and working capital items transferred		$ 163

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ACQUISITIONS AND DIVESTITURES - 2022 Activity (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Proceeds from asset divestitures		$ 256	$ 166	$ 718
Delaware Basin | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Subsequent Event
Business Acquisition [Line Items]
Proceeds from asset divestitures	$ 805

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ACQUISITIONS AND DIVESTITURES - 2021 Activity (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended	3 Months Ended				12 Months Ended
	Oct. 21, 2021	Dec. 31, 2019	Jun. 30, 2021	Mar. 31, 2020	Dec. 31, 2019	Jun. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Proceeds from asset divestitures							$ 256	$ 166	$ 718
Leasehold and property acquisitions amount							9	4	$ 40
Common Class C | BCP | Altus Midstream
Business Acquisition [Line Items]
Business acquisition, equity interest issued or issuable, number of shares	50
Permian Highway Pipeline LLC | BCP
Business Acquisition [Line Items]
Noncontrolling interest, ownership percentage by parent	26.70%
Block 58 Offshore Suriname
Business Acquisition [Line Items]
Ownership percentage		50.00%			50.00%				50.00%
Proceeds received from joint venture					$ 100
Proceeds from joint venture agreement, for reimbursement of cost incurred				$ 79
Joint venture agreement, percentage of costs incurred for reimbursement		50.00%
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount							9	4	$ 40
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Net Property and Equipment			$ 157
Proceeds from asset divestitures			176					87	73
Asset retirement obligation assumed			44
Gain (loss) on sale of oil and gas properties			$ 63					$ 13	$ 33
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Other Non-Core Assets And Leasehold
Business Acquisition [Line Items]
Proceeds from asset divestitures							80
Gain (loss) on sale of oil and gas properties							$ 4
OKLAHOMA | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Net Property and Equipment						$ 206
Proceeds from asset divestitures						223
Gain (loss) on sale of oil and gas properties						$ 17

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ACQUISITIONS AND DIVESTITURES - 2020 Activity (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2021	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Leasehold and property acquisitions amount			$ 9	$ 4	$ 40
Proceeds from sale of oil and gas properties			256	166	718
Gain (loss) on investment in joint venture		$ 19
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount			$ 9	4	40
Permian Region | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties	$ 176			87	73
Gain (loss) on sale of oil and gas properties	$ 63			$ 13	$ 33

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ACQUISITIONS AND DIVESTITURES - 2019 Activity (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Jun. 30, 2021	Sep. 30, 2019	Jun. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties				$ 256	$ 166	$ 718
Impairments				208	4,501	2,949
Leasehold and property acquisitions amount				9	4	40
Permian Region
Business Acquisition [Line Items]
Leasehold and property acquisitions amount				$ 9	4	40
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Oklahoma And Texas
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties		$ 322
Asset retirement obligation assumed		49
Impairments		240
Gain (loss) on sale of oil and gas properties		$ (7)
Disposal Group, Disposed of by Sale, Not Discontinued Operations | OKLAHOMA
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties			$ 223
Gain (loss) on sale of oil and gas properties			17
Net Property and Equipment			$ 206
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Permian Region
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties	$ 176				87	73
Asset retirement obligation assumed	44
Gain (loss) on sale of oil and gas properties	63				$ 13	$ 33
Net Property and Equipment	$ 157

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CAPITALIZED EXPLORATORY WELL COSTS - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized well costs at beginning of year	$ 197	$ 141	$ 159
Additions pending determination of proved reserves	62	226	286
Divestitures and other	(163)	(38)	(100)
Reclassifications to proved properties	(40)	(56)	(179)
Charged to exploration expense	(10)	(76)	(25)
Capitalized well costs at end of year	$ 46	$ 197	$ 141

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CAPITALIZED EXPLORATORY WELL COSTS - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2021 USD ($) Project	Dec. 31, 2020 USD ($) Project	Dec. 31, 2019 USD ($) Project	Dec. 31, 2018 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 13	$ 184	$ 108
Exploratory well costs capitalized for a period greater than one year	33	13	33
Capitalized exploratory well costs	$ 46	$ 197	$ 141	$ 159
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	9,000,000	5	2

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CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 33	$ 13	$ 33
North Sea
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 24

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CAPITALIZED EXPLORATORY WELL COSTS - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 33	$ 13	$ 33
2020
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	24
2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
2018 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
Egypt
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
Egypt | 2020
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Egypt | 2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
Egypt | 2018 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	9
North Sea
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	24
North Sea | 2020
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	24
North Sea | 2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	0
North Sea | 2018 and Prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 0

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details) shares in Thousands, € in Millions	12 Months Ended
	Dec. 31, 2021 EUR (€) Counterparty $ / MMBTU shares
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties | Counterparty	10
Number of preferred units expected to be redeemed before exercise of exchange option (in shares) | shares	250
Expected timing until exercise of exchange option	4 years 5 months 12 days
Foreign currency derivative instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, notional amount | €	€ 15
Derivative, weighted average floor price (in USD per MMBtu)	1.39
Derivative, weighted average ceiling price (in USD per MMBtu)	1.29

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Instruments (Details) - Natural Gas MMBTU in Thousands	12 Months Ended
	Dec. 31, 2021 $ / MMBTU MMBTU
Basis Swap Purchased | January—December 2022 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.45)
Basis Swap Purchased | January to December 2023 | NYMEX Henry Hub/IF Waha
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	29,200
Weighted average price differential | $ / MMBTU	(0.40)
Basis Swap Sold | January—December 2022 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	43,800
Weighted average price differential | $ / MMBTU	(0.08)
Basis Swap Sold | January to December 2023 | NYMEX Henry Hub/IF HSC
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) | MMBTU	29,200
Weighted average price differential | $ / MMBTU	0.02

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities Measured at Fair Value (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Assets:
Derivative asset	$ 0	$ 11
Liabilities:
Derivative liability	113	192
Commodity Derivative Instruments
Assets:
Derivative asset, fair value		11
Derivative asset, netting		0
Derivative asset		11
Liabilities:
Derivative liability, fair value, gross liability	10
Derivative liability, netting	0
Derivative liability	10
Commodity Derivative Instruments | Quoted Price in Active Markets (Level 1)
Assets:
Derivative asset, fair value		0
Liabilities:
Derivative liability, fair value, gross liability	0
Commodity Derivative Instruments | Significant Other Inputs (Level 2)
Assets:
Derivative asset, fair value		11
Liabilities:
Derivative liability, fair value, gross liability	10
Commodity Derivative Instruments | Significant Unobservable Inputs (Level 3)
Assets:
Derivative asset, fair value		0
Liabilities:
Derivative liability, fair value, gross liability	0
Pipeline capacity embedded derivatives
Liabilities:
Derivative liability, fair value, gross liability	46	53
Derivative liability, netting	0	0
Derivative liability	46	53
Pipeline capacity embedded derivatives | Quoted Price in Active Markets (Level 1)
Liabilities:
Derivative liability, fair value, gross liability	0	0
Pipeline capacity embedded derivatives | Significant Other Inputs (Level 2)
Liabilities:
Derivative liability, fair value, gross liability	46	53
Pipeline capacity embedded derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative liability, fair value, gross liability	0	0
Preferred Units embedded derivative
Liabilities:
Derivative liability, fair value, gross liability	57	139
Derivative liability, netting	0	0
Derivative liability	57	139
Preferred Units embedded derivative | Quoted Price in Active Markets (Level 1)
Liabilities:
Derivative liability, fair value, gross liability	0	0
Preferred Units embedded derivative | Significant Other Inputs (Level 2)
Liabilities:
Derivative liability, fair value, gross liability	0	0
Preferred Units embedded derivative | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative liability, fair value, gross liability	$ 57	$ 139

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value Measurement Inputs (Details) $ in Millions	Dec. 31, 2021 USD ($) $ / MMBTU	Dec. 31, 2020 USD ($)
Preferred Units embedded derivative | Recurring
Embedded Derivative [Line Items]
Derivative liability, fair value, gross liability | $	$ 57	$ 139
Significant Unobservable Inputs (Level 3) | Preferred Units embedded derivative | Recurring
Embedded Derivative [Line Items]
Derivative liability, fair value, gross liability | $	$ 57	$ 139
Significant Unobservable Inputs (Level 3) | Measurement Input, Risk Free Interest Rate | Minimum
Embedded Derivative [Line Items]
Preferred Units embedded derivative | $ / MMBTU	0.0554
Significant Unobservable Inputs (Level 3) | Measurement Input, Risk Free Interest Rate | Maximum
Embedded Derivative [Line Items]
Preferred Units embedded derivative | $ / MMBTU	0.1121
Significant Unobservable Inputs (Level 3) | Measurement Input Interest Rate Volatility
Embedded Derivative [Line Items]
Preferred Units embedded derivative	0.4008

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative asset	$ 0	$ 11
Derivative liability	113	192
Current Assets: Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset	0	6
Other Assets: Deferred charges and other
Derivatives, Fair Value [Line Items]
Derivative asset	0	5
Current Liabilities: Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	4	0
Deferred Credits and Other Noncurrent Liabilities: Other
Derivatives, Fair Value [Line Items]
Derivative liability	$ 109	$ 192

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss), net	$ 69	$ (87)	$ (44)
Derivative instrument gains (losses), net	94	(223)	(35)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	25	(136)	9
Unrealized gain (loss), net	69	(87)	(44)
Derivative instrument gains (losses), net	94	(223)	(35)
Commodity Derivative Instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	25	(135)	27
Unrealized gain (loss), net	(20)	11	(44)
Pipeline capacity embedded derivatives | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss), net	7	(61)	8
Foreign currency derivative instruments | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	0	(1)	0
Unrealized gain (loss), net	0	(1)	1
Treasury-lock | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss), net	0	0	(18)
Preferred Units embedded derivative | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss), net	$ 82	$ (36)	$ (9)

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OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 438	$ 492
Drilling advances	55	113
Prepaid assets and other	56	71
Current decommissioning security for sold Gulf of Mexico assets	100	0
Total Other current assets	$ 649	$ 676

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EQUITY METHOD INTERESTS - Additional Information (Details) $ in Millions	Dec. 31, 2021 USD ($) entity	Dec. 31, 2020 USD ($) entity
Equity Method Investments and Joint Ventures [Abstract]
Number of long-haul pipeline entities | entity	4	4
Difference between carrying amount and underlying equity amount | $	$ 34	$ 38

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EQUITY METHOD INTERESTS - Summary of Investments (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Equity method interests	$ 1,365	$ 1,555	$ 1,258
Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	16.00%
Equity method interests	$ 274	284	291
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Interest	15.00%
Equity method interests	$ 0	176	163
Permian Highway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Interest	26.70%
Equity method interests	$ 630	615	311
Shin Oak Pipeline (Breviloba, LLC)
Schedule of Equity Method Investments [Line Items]
Interest	33.00%
Equity method interests	$ 461	$ 480	$ 493

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EQUITY METHOD INTERESTS - Rollforward Activity (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		$ 1,555	$ 1,258
Capital contributions		28	327	$ 501
Distributions		(173)	(97)
Capitalized interest			8
Equity income (loss), net		114	59
Accumulated other comprehensive loss		1
Impairment	$ (160)	(160)	0	0
Equity method interest, ending balance	1,365	1,365	1,555	1,258
ALTM
Movement In Equity Method Interests [Roll Forward]
Capitalized interest			8
Gulf Coast Express Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		284	291
Capital contributions		0	2
Distributions		(50)	(51)
Capitalized interest			0
Equity income (loss), net		40	42
Accumulated other comprehensive loss		0
Impairment		0
Equity method interest, ending balance	274	274	284	291
EPIC Crude Holdings, LP
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		176	163
Capital contributions		2	29
Distributions		0	0
Capitalized interest			0
Equity income (loss), net		(19)	(16)
Accumulated other comprehensive loss		1
Impairment		(160)
Equity method interest, ending balance	0	0	176	163
Permian Highway Pipeline LLC
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		615	311
Capital contributions		26	296
Distributions		(74)	0
Capitalized interest			8
Equity income (loss), net		63	0
Accumulated other comprehensive loss		0
Impairment		0
Equity method interest, ending balance	630	630	615	311
Shin Oak Pipeline (Breviloba, LLC)
Movement In Equity Method Interests [Roll Forward]
Equity method interest, beginning balance		480	493
Capital contributions		0	0
Distributions		(49)	(46)
Capitalized interest			0
Equity income (loss), net		30	33
Accumulated other comprehensive loss		0
Impairment		0
Equity method interest, ending balance	$ 461	$ 461	$ 480	$ 493

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EQUITY METHOD INTERESTS - Summary of Combined Statement of Operations Equity Method Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Operating income	$ 2,888	$ (4,102)	$ (2,152)
Net income	1,402	(4,904)	(3,682)
Equity Method Investment, Nonconsolidated Investee
Schedule of Equity Method Investments [Line Items]
Operating revenues	1,082	707	302
Operating income	548	331	121
Net income	468	256	120
Other comprehensive income (loss)	$ 4	$ 3	$ (8)

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EQUITY METHOD INTERESTS - Summary of Combined Statement of Balance Sheet Equity Method Interests (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Current assets	$ 2,395	$ 1,846
Total assets	14,393	12,746	$ 18,107
Current liabilities	2,231	1,308
Equity	260	(645)	$ 4,465	$ 8,812
Total liabilities and equity	14,393	12,746
Equity Method Investment, Nonconsolidated Investee
Schedule of Equity Method Investments [Line Items]
Current assets	280	260
Noncurrent assets	7,445	7,678
Total assets	7,725	7,938
Current liabilities	153	206
Noncurrent liabilities	1,193	1,191
Equity	6,379	6,541
Total liabilities and equity	$ 7,725	$ 7,938

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OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Accrued operating expenses	$ 129	$ 91
Accrued exploration and development	206	167
Accrued compensation and benefits	292	170
Accrued interest	107	140
Accrued income taxes	28	25
Current asset retirement obligation	41	56
Current operating lease liability	99	116
Current decommissioning contingency for sold Gulf of Mexico properties	100	0
Other	168	97
Total Other current liabilities	$ 1,170	$ 862

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ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the year	$ 1,944	$ 1,858
Liabilities incurred	3	10
Liabilities divested	(44)	(26)
Liabilities settled	(32)	(30)
Accretion expense	113	109
Revisions in estimated liabilities	146	23
Asset retirement obligation at end of the year	2,130	1,944
Less current portion	(41)	(56)
Asset retirement obligation, long-term	$ 2,089	$ 1,888

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ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 3	$ 10
Revisions in estimated liabilities	$ 146	$ 23

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DEBT AND FINANCING COSTS - Additional Information (Details) £ in Millions				1 Months Ended		3 Months Ended	12 Months Ended
	Nov. 03, 2020 USD ($)	Aug. 18, 2020 USD ($)	Jun. 21, 2019 USD ($)	Mar. 31, 2019	Nov. 30, 2018 USD ($) contract	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2021 GBP (£)	Dec. 31, 2020 GBP (£)	Aug. 17, 2020 USD ($)	Mar. 31, 2020 USD ($)	Jun. 19, 2019 USD ($)	Dec. 31, 2018	Mar. 31, 2018 USD ($)
Debt Instrument [Line Items]
Loss (gain) from extinguishment of debt							$ 104,000,000	$ (160,000,000)	$ 75,000,000
Unamortized discount							30,000,000	35,000,000
Commercial paper, average outstanding								0
Debt issuance costs							39,000,000	57,000,000
Discount of debt amortization							6,000,000	7,000,000	$ 2,000,000
Current maturities							$ 215,000,000	2,000,000
Altus Midstream LP
Debt Instrument [Line Items]
Debt leverage ratio (less than)							4.00			4.00
Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount		$ 644,000,000	$ 932,000,000					588,000,000				$ 1,250,000,000		$ 1,000,000,000
Extinguishment of debt amount			1,000,000,000
Loss (gain) from extinguishment of debt		(2,000,000)	75,000,000					(158,000,000)
Unamortized debt issuance costs and discount			$ 7,000,000
Discount to par of debt repurchase		38,000,000						168,000,000
Debt repurchase price		644,000,000						428,000,000
Debt instrument, repurchase early tender premium		32,000,000
Debt repurchase, accrued and unpaid interest		$ 6,000,000
Senior Notes | Debt Repurchase, Cash Tender Offers
Debt Instrument [Line Items]
Debt repurchased principle amount						$ 1,700,000,000
Loss (gain) from extinguishment of debt						105,000,000
Unamortized debt issuance costs and discount						11,000,000
Debt repurchase price						$ 1,800,000,000
Senior Notes | Open Market Repurchase
Debt Instrument [Line Items]
Debt repurchased principle amount							$ 22,000,000
Loss (gain) from extinguishment of debt							(1,000,000)
Discount to par of debt repurchase							2,000,000
Debt repurchase price							20,000,000
4.250% Notes Due January 15, 2030 | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount														$ 600,000,000
Debt interest rate														4.25%
5.350% Notes Due July 1, 2049 | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount														$ 400,000,000
Debt interest rate														5.35%
Apache credit facility
Debt Instrument [Line Items]
Line of credit outstanding							$ 542,000,000	150,000,000
Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, committed amount																$ 4,000,000,000
Debt extension term				1 year
Quarterly facility fees at per annum rate							0.25%
Maximum potential lien on assets located in specified regions							$ 1,900,000,000
Apache credit facility | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt-to-capital ratio															0.60
Percentage of liens of companies consolidated asset							15.00%			15.00%
Apache credit facility | Revolving Credit Facility | Base Rate
Debt Instrument [Line Items]
Margin percentage							0.50%
Apache credit facility | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Margin percentage							1.50%
4.875% Senior Notes Due In 2027 | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount												$ 750,000,000
Debt interest rate												4.875%
4.625% Senior Notes Due In 2025 | Senior Notes
Debt Instrument [Line Items]
Debt repurchased principle amount												$ 500,000,000
Debt interest rate												4.625%
3.625% notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Debt interest rate	3.625%
Current maturities	$ 183,000,000
Redemption price, percentage of principal amount redeemed	100.00%
Line of Credit | Altus Midstream LP
Debt Instrument [Line Items]
Debt covenant leverage ratio							5.00			5.00
Incentive distribution							$ 30,000,000
Adjusted pursuant agreement consecutive equals or exceeds							$ 350,000,000
Line of Credit | Altus Midstream LP | Maximum
Debt Instrument [Line Items]
Debt covenant leverage ratio							5.50			5.50
Line of Credit | Altus Midstream LP | Minimum
Debt Instrument [Line Items]
Debt covenant leverage ratio							4.00			4.00
Line of Credit | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Letters of credit outstanding, amount							$ 2,000,000	0
Debt extension term					1 year
Line of credit facility maximum borrowing capacity					$ 800,000,000
Line of credit facility, number of extension options | contract					2
Line of credit facility, maximum borrowing capacity, if adding new lenders					$ 1,500,000,000
Line of Credit | Letter of Credit | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity					100,000,000
Line of Credit | Swingline Loan Subfacility | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity					$ 100,000,000
Line of Credit | Uncommitted Lines of Credit
Debt Instrument [Line Items]
Line of credit outstanding							0	0
Line of Credit | Uncommitted Lines of Credit | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount							17,000,000	17,000,000		£ 117	£ 34
Line of Credit | Apache credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity													$ 5,000,000,000
Line of Credit | Apache credit facility | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding, amount							20,000,000	40,000,000		£ 748	£ 633
Line of credit facility, committed amount							2,080,000,000.00
Line of credit facility maximum borrowing capacity							3,000,000,000
Line of Credit | Altus credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit outstanding							657,000,000	624,000,000
Line of Credit | Altus credit facility | Revolving Credit Facility | Altus Midstream LP
Debt Instrument [Line Items]
Line of credit outstanding							$ 657,000,000	$ 624,000,000

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DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($) $ in Millions	Jan. 18, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term debt, gross		$ 6,344	$ 8,052
Finance lease obligations		36	38
Unamortized discount		(30)	(35)
Debt issuance costs		(39)	(57)
Total debt		7,510	8,772
Current maturities		(215)	(2)
Long-term debt		7,295	8,770
Apache credit facility
Debt Instrument [Line Items]
Credit facility		542	150
Notes and debentures before unamortized discount and debt issuance costs
Debt Instrument [Line Items]
Debt fair value		7,100	8,500
Unsecured Debt | 3.25% notes due 2022
Debt Instrument [Line Items]
Long-term debt, gross		$ 213	213
Debt interest rate		3.25%
Unsecured Debt | 3.25% notes due 2022 | Subsequent Event
Debt Instrument [Line Items]
Debt interest rate	3.25%
Redemption price, percentage of principal amount redeemed	100.00%
Unsecured Debt | 2.625% notes due 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 123	123
Debt interest rate		2.625%
Unsecured Debt | 4.625% notes due 2025
Debt Instrument [Line Items]
Long-term debt, gross		$ 500	500
Debt interest rate		4.625%
Unsecured Debt | 7.7% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross		$ 79	79
Debt interest rate		7.70%
Unsecured Debt | 7.95% notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross		$ 133	133
Debt interest rate		7.95%
Unsecured Debt | 4.875% notes due 2027
Debt Instrument [Line Items]
Long-term debt, gross		$ 378	750
Debt interest rate		4.875%
Unsecured Debt | 4.375% notes due 2028
Debt Instrument [Line Items]
Long-term debt, gross		$ 703	993
Debt interest rate		4.375%
Unsecured Debt | 7.75% notes due in 2029
Debt Instrument [Line Items]
Long-term debt, gross		$ 235	235
Debt interest rate		7.75%
Unsecured Debt | 4.25% notes due 2030
Debt Instrument [Line Items]
Long-term debt, gross		$ 580	580
Debt interest rate		4.25%
Unsecured Debt | 6.0% notes due 2037
Debt Instrument [Line Items]
Long-term debt, gross		$ 443	443
Debt interest rate		6.00%
Unsecured Debt | 5.1% notes due 2040
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,333	1,333
Debt interest rate		5.10%
Unsecured Debt | 5.25% notes due 2042
Debt Instrument [Line Items]
Long-term debt, gross		$ 399	399
Debt interest rate		5.25%
Unsecured Debt | 4.75% notes due 2043
Debt Instrument [Line Items]
Long-term debt, gross		$ 428	1,133
Debt interest rate		4.75%
Unsecured Debt | 4.25% notes due 2044
Debt Instrument [Line Items]
Long-term debt, gross		$ 221	559
Debt interest rate		4.25%
Unsecured Debt | 7.375% debentures due 2047
Debt Instrument [Line Items]
Long-term debt, gross		$ 150	150
Debt interest rate		7.375%
Unsecured Debt | 5.35% notes due 2049
Debt Instrument [Line Items]
Long-term debt, gross		$ 387	390
Debt interest rate		5.35%
Unsecured Debt | 7.625% debentures due 2096
Debt Instrument [Line Items]
Long-term debt, gross		$ 39	39
Debt interest rate		7.625%
Commercial paper
Debt Instrument [Line Items]
Long-term debt, gross		$ 0	0
Line of Credit | Altus credit facility | Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility		$ 657	$ 624

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DEBT AND FINANCING COSTS - Schedule of Long Term Debt by Maturity (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
2022	$ 213
2023	123
2024	0
2025	500
2026	212
Thereafter	5,296
Notes and debentures, excluding discounts and debt issuance costs	$ 6,344	$ 8,052

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DEBT AND FINANCING COSTS - Components of Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Interest expense	$ 419	$ 438	$ 430
Amortization of debt issuance costs	8	8	7
Capitalized interest	0	(12)	(37)
Loss (gain) on extinguishment of debt	104	(160)	75
Interest income	(8)	(7)	(13)
Interest income from APA Corporation, net	(51)	0	0
Financing costs, net	$ 472	$ 267	$ 462

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INCOME TAXES - Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
U.S.	$ 689	$ (4,581)	$ (4,397)
Foreign	1,291	(259)	1,389
NET INCOME (LOSS) BEFORE INCOME TAXES	$ 1,980	$ (4,840)	$ (3,008)

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INCOME TAXES - Total Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current income taxes:
Federal	$ 16	$ (2)	$ 1
Foreign	636	178	659
Total current income taxes	652	176	660
Deferred income taxes:
Federal	0	0	67
Foreign	(74)	(112)	(53)
Total deferred income taxes	(74)	(112)	14
Total	$ 578	$ 64	$ 674

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INCOME TAXES - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at U.S. statutory rate	$ 416	$ (1,016)	$ (631)
State income tax, less federal effect	0	0	1
Taxes related to foreign operations	300	97	328
Tax credits	(10)	(13)	(6)
Net change in tax contingencies	16	1	1
Goodwill impairment	0	35	0
Valuation allowances	(111)	965	972
Tax attributable to Altus Preferred Unit limited partners	(34)	(16)	(8)
All other, net	1	11	17
Total	$ 578	$ 64	$ 674

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INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
U.S. and state net operating losses	$ 2,494	$ 2,306
Capital losses	647	633
Tax credits and other tax incentives	24	33
Foreign tax credits	2,241	2,241
Accrued expenses and liabilities	152	93
Asset retirement obligation	712	654
Property and equipment	3	261
Investment in Altus Midstream LP	64	76
Net interest expense limitation	135	252
Lease liability	81	79
Decommissioning contingency for sold Gulf of Mexico properties	263	0
Other	1	1
Total deferred tax assets	6,817	6,629
Valuation allowance	(5,875)	(5,991)	$ (4,959)	$ (3,947)
Net deferred tax assets	942	638
Deferred tax liabilities:
Equity investments	2	4
Property and equipment	748	750
Right-of-use asset	77	74
Decommissioning security for sold Gulf of Mexico properties	164	0
Other	86	13
Total deferred tax liabilities	1,077	841
Net deferred income tax liability	$ 135	$ 203

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INCOME TAXES - Net Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Assets:
Deferred charges and other	$ 13	$ 12
Liabilities:
Income taxes	148	215
Net deferred income tax liability	$ 135	$ 203

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INCOME TAXES - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax [Line Items]
Net interest expense carryforward	$ 610
Capital losses	647	$ 633
Foreign tax credit carryforward, amount	2,241	2,241
Tax expense recorded for interest and penalties	1	1	$ 1
Accrued for payment of interest and penalties	4	3	2
(Reduction) increase reserve for uncertain tax positions related to the current year	23	$ 11	$ 58
U.S.
Income Tax [Line Items]
Operating loss carryforwards	9,717
Operating loss carryforwards subject to annual limitation	177
Capital losses	$ 1,900
Capital loss carryforward carryover period	5 years
Canada
Income Tax [Line Items]
Operating loss carryforwards	$ 1
Capital losses	$ 836

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INCOME TAXES - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Increase (decrease) of valuation allowances	$ (116)	$ 1,000	$ 1,000
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	5,991	4,959	3,947
State	1	67	41
U.S.	(112)	960	971
Foreign	(5)	5	0
Balance at end of year	$ 5,875	$ 5,991	$ 4,959

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INCOME TAXES - Net Operating Losses (Details) $ in Millions	Dec. 31, 2021 USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 9,717
State
Schedule Of Income Tax [Line Items]
Net operating losses	6,695
Foreign
Schedule Of Income Tax [Line Items]
Net operating losses	$ 1

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INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Foreign tax credit carryforward, amount	$ 2,241	$ 2,241

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INCOME TAXES - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 116	$ 93	$ 82	$ 24
Additions based on tax positions related to prior year	16	0	49
Additions based on tax positions related to the current year	7	11	9
Balance at end of year	$ 116	$ 93	$ 82	$ 24

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COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions							3 Months Ended		12 Months Ended
	Sep. 10, 2020 defendant	Sep. 11, 2019 USD ($) plaintiff	Dec. 20, 2017 Action	Jul. 17, 2017 Action defendant	Mar. 21, 2016 USD ($)	Mar. 20, 2016 USD ($)	Dec. 31, 2021 USD ($) bond subsidiary	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($) subsidiary bond Action	Dec. 31, 2020 USD ($) sidetrack	Dec. 31, 2019 USD ($)	Dec. 31, 2013 USD ($) source	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)	Mar. 12, 2014 USD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies							$ 84,000,000		$ 84,000,000
Environmental tax and royalty obligations															$ 100,000,000
Retain right of obligations							45,000,000		45,000,000
Number of plaintiffs | plaintiff		4
Maximum cost considered to be recognized for additional reserve							300,000		300,000
Undiscounted reserve for environmental remediation							2,000,000		2,000,000
Standby loan agreed to provide related to ARO							400,000,000		400,000,000
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)							1,086,000,000		1,086,000,000	$ 0
Decommissioning contingency for sold properties, total							1,200,000,000		1,200,000,000
Current decommissioning contingency for sold Gulf of Mexico properties							100,000,000		100,000,000	0
Decommissioning security for sold Gulf of Mexico properties (Note 12)							640,000,000		640,000,000	0
Decommissioning security for sold Gulf of Mexico properties, total							740,000,000		740,000,000
Current decommissioning security for sold Gulf of Mexico assets							$ 100,000,000		100,000,000
Loss on previously sold Gulf of Mexico properties								$ 446,000,000	446,000,000	0	$ 0
Fixed operating lease expenses									127,000,000	149,000,000	222,000,000
Depreciation on finance lease asset									2,000,000	2,000,000	7,000,000
Interest on finance lease asset									2,000,000	2,000,000	3,000,000
Exploration, development, and operating activities									161,000,000	328,000,000	468,000,000
Variable lease payment									$ 63,000,000	$ 41,000,000	78,000,000
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]							Current debt		Current debt	Current debt
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]							LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)		LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)	LONG-TERM DEBT (Note 10) ($657 and $624 related to Altus VIE)
Egypt
Commitment And Contingencies [Line Items]
Exploration, development, and operating activities									$ 86,000,000	$ 102,000,000	$ 139,000,000
Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Loss contingency damages sought value					$ 200,000,000
Canadian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Loss contingency punitive damages		$ 60,000,000
California Litigation
Commitment And Contingencies [Line Items]
Number of actions filed | Action			2	3
Number of defendants | defendant				30
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants | defendant	25
Castex Lawsuit
Commitment And Contingencies [Line Items]
Loss contingency damages sought value										200,000,000
Loss contingency estimate of possible loss							$ 13,500,000		13,500,000	$ 60,000,000
Number of sidetracks | sidetrack										5
Oklahoma Class Actions
Commitment And Contingencies [Line Items]
Loss contingency damages sought value									$ 200,000,000
Number of actions filed | Action									2
Litigation settlement, amount awarded to other party							$ 25,000,000
Apache Australia Operation | Australian Operations Divestiture Dispute
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount														$ 80
Loss contingency estimate of possible loss													$ 200
Gulf Of Mexico Shelf Operations And Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Commitment And Contingencies [Line Items]
Proceeds from sale of operations and properties												$ 3,750,000,000
Trust account for disposal group, number of net profits interests | source												2
Number of bonds held | bond							2		2
Number of debt instruments held | subsidiary							5		5
Minimum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							$ 1,200,000,000		$ 1,200,000,000
Minimum | Apollo Exploration Lawsuit
Commitment And Contingencies [Line Items]
Loss contingency damages sought value						$ 1,100,000,000
Maximum
Commitment And Contingencies [Line Items]
Asset retirement obligation, estimated liability							$ 1,400,000,000		$ 1,400,000,000

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COMMITMENTS AND CONTINGENCIES - Company's Weighted Average Lease Term and Discount Rate related to Leases (Details)	Dec. 31, 2021
Accounting Policies [Abstract]
Operating leases, weighted average remaining lease term	3 years 4 months 24 days
Finance leases, weighted average remaining lease term	11 years 8 months 12 days
Operating leases, weighted average discount rate	3.70%
Finance leases, weighted average discount rate	4.40%

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COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
2022	$ 106
2023	75
2024	58
2025	7
2026	7
Thereafter	18
Total future minimum payments	271
Less: imputed interest	(22)
Total lease liabilities	249
Current portion	99	$ 116
Non-current portion	$ 150
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)	Other current liabilities (Note 8) ($15 and $4 related to Altus VIE)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other ($67 and $144 related to Altus VIE)	Other ($67 and $144 related to Altus VIE)
Finance Leases
2022	$ 3
2023	3
2024	3
2025	4
2026	4
Thereafter	25
Total future minimum payments	42
Less: imputed interest	(6)
Total lease liabilities	36	$ 38
Current portion	2
Non-current portion	34
Purchase Obligations
2022	230
2023	199
2024	161
2025	159
2026	3,637
Thereafter	463
Total future minimum payments	4,849
Total costs under take or pay and throughout obligation	194	$ 120	$ 111
Purchase commitment, remaining minimum amount committed	$ 3,500

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50.00%
Maximum percentage of compensation contributed by the company	8.00%
Percentage of additional contribution to money purchase retirement plan	6.00%
Maximum percentage of eligible compensation contributed by the participating employees	50.00%
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested	75.00%
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested	20.00%
Annual cost of retirement benefit plans	$ 31	$ 43	$ 52
Targeted ongoing funding level of pension plan policy, percent	100.00%
Outperformance relative to gilts for equities	3.50%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 205	$ 207	$ 181
Expected contribution towards pension and postretirement plan	5
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 262
Fair value of plan assets at end of year	254	$ 262
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	233	199	$ 187
Service cost	3	3	3
Interest cost	3	4	5
Foreign currency exchange rates	(2)	8	7
Actuarial losses (gains)	(5)	30	15
Plan settlements	(17)	0	(14)
Benefits paid	(4)	(11)	(4)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	211	233	199
Change in Plan Assets
Fair value of plan assets at beginning of year	262	228	208
Actual return on plan assets	11	31	25
Foreign currency exchange rates	(3)	9	8
Employer contributions	5	5	5
Plan settlements	(17)	0	(14)
Benefits paid	(4)	(11)	(4)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	254	262	228
Funded status at end of year	43	29	29
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	43	29	29
Amounts recognized in Consolidated Balance Sheet	43	29	29
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 1	$ (11)	$ (7)
Weighted Average Assumptions used as of December 31
Discount rate	1.80%	1.40%	2.10%
Salary increases	4.90%	4.50%	4.30%
Expected return on assets	1.90%	1.50%	2.20%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 20	$ 20	$ 27
Service cost	1	1	2
Interest cost	0	0	1
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	1	1	(9)
Plan settlements	0	0	0
Benefits paid	(4)	(4)	(2)
Retiree contributions	2	2	1
Projected benefit obligation at end of year	20	20	20
Change in Plan Assets
Fair value of plan assets at beginning of year	0	0	0
Actual return on plan assets	0	0	0
Foreign currency exchange rates	0	0	0
Employer contributions	2	2	1
Plan settlements	0	0	0
Benefits paid	(4)	(4)	(2)
Retiree contributions	2	2	1
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(20)	(20)	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(2)
Non-current liability	(18)	(18)	(18)
Amounts recognized in Consolidated Balance Sheet	(20)	(20)	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 14	$ 16	$ 19
Weighted Average Assumptions used as of December 31
Discount rate	2.57%	2.06%	3.00%
Healthcare cost trend
Initial	6.25%	6.00%	6.25%
Ultimate in 2025	5.00%	5.00%	5.00%

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Percentage of Plan Assets at Year-End	100.00%	100.00%
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	15.00%
Percentage of Plan Assets at Year-End	15.00%	19.00%
Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	15.00%
Percentage of Plan Assets at Year-End	15.00%	19.00%
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	79.00%
Percentage of Plan Assets at Year-End	79.00%	80.00%
U.K. government bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	55.00%
Percentage of Plan Assets at Year-End	54.00%	64.00%
U.K. corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	24.00%
Percentage of Plan Assets at Year-End	25.00%	16.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	6.00%
Percentage of Plan Assets at Year-End	6.00%	1.00%

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 254	$ 262
Equity securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38	49
Overseas quoted equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38	49
Debt securities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	200	211
U.K. government bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	138	168
U.K. corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	62	43
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 16	$ 2

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.50%	4.30%	4.70%
Expected return on assets	1.50%	2.20%	2.80%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 3	$ 3	$ 3
Interest cost	3	4	5
Expected return on assets	(4)	(5)	(5)
Amortization of loss	0	0	0
Settlement loss	0	0	0
Net periodic benefit cost	$ 2	$ 2	$ 3
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	1.40%	2.10%	2.90%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 2
Interest cost	0	0	1
Expected return on assets	0	0	0
Amortization of loss	(1)	(1)	(1)
Settlement loss	0	0	0
Net periodic benefit cost	$ 0	$ 0	$ 2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	2.06%	3.00%	4.13%
Healthcare cost trend
Initial	6.00%	6.25%	6.50%
Ultimate in 2025	5.00%	5.00%	5.00%

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RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2021 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	$ 6
2023	7
2024	6
2025	6
2026	6
Years 2027-2031	39
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	2
2023	2
2024	2
2025	2
2026	2
Years 2027-2031	$ 6

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REDEMABLE NONCONTROLLING INTEREST - ALTUS - Additional Information (Details) - Altus Midstream LP $ in Millions	Jun. 12, 2019 USD ($) qtr	Dec. 31, 2021 USD ($)
Class of Stock [Line Items]
Preferred Units, redemption terms, internal rate of return		11.50%
Preferred Units embedded derivative	$ 94	$ 57
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Aggregate issue price of Preferred Units	625
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	$ 611
Preferred Units, quarterly distribution rate per annum	7.00%
Preferred Units, increased quarterly distribution rate per annum upon specified events	10.00%
Preferred Units, distribution in-kind, number of quarters after issuance | qtr	6
Preferred Units, redemption terms, internal rate of return	11.50%
Preferred Units, redemption terms, internal rate of return after fifth anniversary of closing	13.75%
Preferred Units, redemption terms, multiple of invested capital	1.3	1.3
Preferred Units, exchangeable, number of preceding trading days	20 days
Preferred Units, exchangeable, discount percentage	6.00%
Maximum amount of distributions to common unit holders	$ 650
Issue discount	4
Transaction costs	10
Preferred Units embedded derivative	$ 94

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REDEMABLE NONCONTROLLING INTEREST - ALTUS - Schedule of Preferred Units (Details) - Altus Midstream LP - USD ($) $ in Millions	Dec. 31, 2021	Jun. 12, 2019
Class of Stock [Line Items]
Preferred Units embedded derivative	$ 57	$ 94
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners
Class of Stock [Line Items]
Redeemable noncontrolling interest - Altus Preferred Unit limited partners		517
Preferred Units embedded derivative		94
Transaction price, net		$ 611

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REDEMABLE NONCONTROLLING INTEREST - ALTUS - Activity Related to Preferred Units (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 12, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	$ 608	$ 555	$ 0
Cash distributions to Altus Preferred Unit limited partners	(46)	(23)	0
Distributions payable to Altus Preferred Unit limited partners	(12)
Ending balance	712	$ 608	$ 555
Altus Midstream LP
Increase (Decrease) in Temporary Equity [Roll Forward]
Preferred Units embedded derivative(2)	57
Redeemable noncontrolling interest, net of embedded derivative liability	$ 769
Preferred Units, redemption terms, internal rate of return	11.50%
Preferred units, redemption price	$ 739
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners | Altus Midstream LP
Movement In Preferred Units [Roll Forward]
Preferred Units: beginning of period (in shares)	660,694	638,163
Distribution of in-kind additional Preferred Units (in shares)			22,531
Preferred Units: end of period (in shares)	660,694	660,694	638,163
Increase (Decrease) in Temporary Equity [Roll Forward]
Beginning balance	$ 608	$ 555
Distribution of in-kind additional Preferred Units			$ 0
Cash distributions paid to Preferred Unit limited partners			(23)
Cash distributions to Altus Preferred Unit limited partners		(46)
Distributions payable to Altus Preferred Unit limited partners	(12)
Allocation of Altus Midstream net income		80	76
Accreted value adjustment		82
Ending balance	$ 712	$ 608	$ 555
Preferred Units, redemption terms, internal rate of return				11.50%
Preferred Units, redemption terms, multiple of invested capital	1.3			1.3

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CAPITAL STOCK AND EQUITY - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended	12 Months Ended
	Jan. 31, 2022 USD ($) $ / shares shares	Jan. 31, 2021 shares	Mar. 31, 2020 $ / shares	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2020 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Mar. 01, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, conversion ratio							1
Common stock, quarterly dividend (in USD per share) | $ / shares			$ 0.025			$ 0.25
Dividends, common stock, cash | $				$ (9)	$ (38)	$ (376)
Payments of capital distribution to parent | $				$ 43
Shares authorized and available for grant (in shares)				11,000,000
Shares Issued in the period (in shares)				0	0	0
Shares exercised in the period (in shares)				0	0	0
Stock-settled and cash-settled compensation expensed | $				$ 152	$ 40	$ 110
Stock-settled and cash-settled compensation capitalized | $				18	7	28
Subsequent Event | 2022 Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Paid-In Capital
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividends, common stock, cash | $				(9)	(38)	(376)
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-settled and cash-settled compensation expensed | $				91	39	104
Stock-settled and cash-settled compensation capitalized | $				$ 15	$ 6	$ 24
Awards granted during period (in shares)				1,506,000	1,352,000	1,479,000
Weighted average grant date fair value per share (in USD per share) | $ / shares				$ 16.46	$ 24.60	$ 36.81
Total compensation cost related to non-vested awards not yet recognized | $				$ 14
Restricted Stock | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Awards granted during period (in shares)	775,942
Weighted average grant date fair value per share (in USD per share) | $ / shares	$ 29.46
Total compensation cost related to non-vested awards not yet recognized | $	$ 23
Restricted Stock | ALTM | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share) | $ / shares	$ 63.63
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				4,441,000	3,462,000	4,831,000
Total compensation cost related to non-vested awards not yet recognized | $				$ 74
Phantom Units | 2020 Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)		1,959,856
Phantom Units | 2020 Performance Program | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)		0
Phantom Units | 2020 Performance Program | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)		3,709,472
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,512,602
Total compensation cost related to non-vested awards not yet recognized | $	$ 76
Phantom Units | Subsequent Event | 2022 Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	1,093,034
Phantom Units | Subsequent Event | 2022 Performance Program | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	0
Phantom Units | Subsequent Event | 2022 Performance Program | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	2,186,068
Phantom Units | ALTM | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	27,643
Total compensation cost related to non-vested awards not yet recognized | $	$ 2
In or after 2016 | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable				3 years
Period in which stock options expires after grant date				10 years

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CAPITAL STOCK AND EQUITY - Description of Stock Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Stock-settled and cash-settled compensation expensed	$ 152	$ 40	$ 110
Stock-settled and cash-settled compensation capitalized	18	7	28
Total stock-settled and cash-settled compensation costs	$ 170	$ 47	$ 138

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CAPITAL STOCK AND EQUITY - Summary of Stock Options Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning of year, Shares (in shares)	3,537,000	4,298,000	4,872,000
Exercised, Shares (in shares)	0	0	0
Forfeited, Shares (in shares)	0	(37,000)	(80,000)
Expired, Shares (in shares)	(525,000)	(724,000)	(494,000)
Outstanding, end of year, Shares (in shares)	3,012,000	3,537,000	4,298,000
Expected to vest, Shares (in shares)	0	150,000	495,000
Exercisable, end of year, Shares (in shares)	3,012,000	3,387,000	3,803,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding, beginning of year, weighted average exercise price (in USD per share)	$ 72.10	$ 75.24	$ 75.95
Forfeited, weighted average exercise price (in USD per share)	0	44.98	34.58
Expired, weighted average exercise price (in USD per share)	119.83	92.14	88.82
Outstanding, end of year, weighted average exercise price (in USD per share)	63.79	72.10	75.24
Expected to vest, weighted average exercise price (in USD per share)	0	45.77	49.11
Exercisable, end of year, weighted average exercise price (in USD per share)	$ 63.79	$ 73.26	$ 78.64
Weighted average remaining contractual life for options outstanding	3 years 1 month 6 days
Aggregate intrinsic value for options outstanding	$ 0.0
Weighted average remaining contractual life for exercisable	3 years 1 month 6 days
Aggregate intrinsic value for exercisable	$ 0.0

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CAPITAL STOCK AND EQUITY - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Weighted Average  Grant-Date  Fair Value
Total fair value of restricted stock awards vested	$ 25	$ 94	$ 103
Restricted Stock
Units
Non-vested, beginning balance (in shares)	1,552,000	2,448,000	3,153,000
Granted, Shares (in shares)	1,506,000	1,352,000	1,479,000
Vested, Shares (in shares)	(857,000)	(1,933,000)	(1,899,000)
Forfeited, Shares (in shares)	(128,000)	(315,000)	(285,000)
Non-vested, ending balance (in shares)	2,073,000	1,552,000	2,448,000
Weighted Average  Grant-Date  Fair Value
Non-vested Beginning Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 28.43	$ 46.65	$ 55.54
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	16.46	24.60	36.81
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	29.13	48.65	53.99
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	19.78	30.09	45.06
Non-vested Ending Balance, Weighted Average Grant Date Fair Value (in USD per share)	$ 19.98	$ 28.43	$ 46.65
Total compensation cost related to non-vested awards not yet recognized	$ 14
Unvested restricted stock units (in shares)	2,073,419
Weighted-average remaining life of unvested restricted stock units	9 months 18 days
Phantom Units
Units
Non-vested, beginning balance (in shares)	4,423,000	5,384,000	1,818,000
Reverse stock split (in shares)	0	(1,246,000)	0
Granted, Shares (in shares)	4,441,000	3,462,000	4,831,000
Vested, Shares (in shares)	(2,049,000)	(1,618,000)	(616,000)
Forfeited, Shares (in shares)	(413,000)	(1,559,000)	(649,000)
Non-vested, ending balance (in shares)	6,402,000	4,423,000	5,384,000
Weighted Average  Grant-Date  Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 74
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted, Shares (in shares)	4,375,546	3,378,486
Phantom Units Issued Based on Per-Share Market Price of ALTM Common Stock
Units
Granted, Shares (in shares)	65,327	83,239
Cash-settled conditional restricted stock unit | Performance Program
Units
Non-vested, beginning balance (in shares)	3,417,000
Granted, Shares (in shares)	1,782,000
Vested, Shares (in shares)	(76,000)
Forfeited, Shares (in shares)	(240,000)
Non-vested, ending balance (in shares)	4,531,000	3,417,000
Weighted Average  Grant-Date  Fair Value
Expired, Shares (in shares)	(352,000)

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CAPITAL STOCK AND EQUITY - Performance Program Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended						6 Months Ended	12 Months Ended
	Jan. 31, 2022 $ / shares shares	Jan. 31, 2021 shares	Jan. 31, 2020 shares	Jan. 31, 2019 shares	Jan. 31, 2018 shares	Jan. 31, 2017 shares	Jun. 30, 2021	Dec. 31, 2021 USD ($) shares	Dec. 31, 2020 USD ($) shares	Dec. 31, 2019 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)								11,000,000
Compensation expense | $								$ 152	$ 40	$ 110
Stock-settled and cash-settled compensation capitalized | $								$ 18	$ 7	$ 28
Altus Midstream LP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reverse stock split ratio							0.05
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)								4,441,000	3,462,000	4,831,000
Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,512,602
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage								50.00%
Shares vesting period								3 years
Compensation expense | $								$ 56	$ 8	$ 24
Stock-settled and cash-settled compensation capitalized | $								$ 3	$ 1	$ 3
Performance Program | Vesting, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage								50.00%
Performance Program | Vesting, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage								50.00%
2017 Performance Program | Conditional Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)						620,885
Total awards, outstanding (in shares)								1,868
Shares paid out as percentage of target								54.00%
2018 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)					931,049
Total awards, outstanding (in shares)								97,645
Shares paid out as percentage of target								23.00%
2019 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				1,679,832
Total awards, outstanding (in shares)								1,247,706
Shares paid out as percentage of target								100.00%
2020 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)			1,687,307
Total awards, outstanding (in shares)								1,330,823
2020 Performance Program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target			0.00%
Shares authorized and available for grant (in shares)			0
2020 Performance Program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target			200.00%
Shares authorized and available for grant (in shares)			2,661,646
2021 Performance Program | Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)		1,959,856
Total awards, outstanding (in shares)								1,854,736
2021 Performance Program | Phantom Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target		0.00%
Shares authorized and available for grant (in shares)		0
2021 Performance Program | Phantom Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares awarded of target		20000.00%
Shares authorized and available for grant (in shares)		3,709,472
2022 Performance Program | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage	50.00%
Shares vesting period	3 years
Shares vesting percentage	50.00%
2022 Performance Program | Phantom Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	1,093,034
2022 Performance Program | Phantom Units | Subsequent Event | Vesting, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share) | $ / shares	$ 41.88
2022 Performance Program | Phantom Units | Subsequent Event | Vesting, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share (in USD per share) | $ / shares	$ 29.46
2022 Performance Program | Phantom Units | Minimum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	0
2022 Performance Program | Phantom Units | Maximum | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	2,186,068

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CAPITAL STOCK AND EQUITY - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Weighted Average  Grant-Date  Fair Value
Employee-related liabilities, current	$ 292	$ 170
Performance Program | Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	3,417
Vested, Shares (in shares)	(76)
Non-vested, ending balance (in shares)	4,531	3,417
Weighted Average  Grant-Date  Fair Value
Employee-related liabilities, current	$ 36

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Share of equity method interests other comprehensive loss	$ 0	$ (1)	$ (1)
Pension and postretirement benefit plan (Note 13)	22	15	17
Accumulated other comprehensive income	$ 22	$ 14	$ 16

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MAJOR CUSTOMERS (Details) - Customer Concentration Risk - Oil and Gas Production Revenues	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	14.00%	17.00%
CFE International
Revenue, Major Customer [Line Items]
Concentration risk percentage	10.00%
Vitol
Revenue, Major Customer [Line Items]
Concentration risk percentage		14.00%
BP plc
Revenue, Major Customer [Line Items]
Concentration risk percentage			10.00%
China Petroleum & Chemical Corporation (Sinopec)
Revenue, Major Customer [Line Items]
Concentration risk percentage			11.00%

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BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021 Segment
Segment Reporting [Abstract]
Number of reporting segments	3

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BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Expenses:
Lease operating expenses		$ 1,241	$ 1,127	$ 1,447
Taxes other than income		204	123	207
Exploration		127	274	805
Depreciation, depletion, and amortization		1,360	1,772	2,680
Asset retirement obligation accretion		113	109	107
Impairments	$ 1,400	208	4,501	2,949
Total operating expenses		5,097	8,537	8,643
Operating Income (Loss)		2,888	(4,102)	(2,152)
Other Income (Expense):
Gain on divestitures, net		67	32	43
Loss on previously sold Gulf of Mexico properties		(446)
Derivative instrument gains (losses), net		94	(223)	(35)
Other		228	64	54
General and administrative		(357)	(290)	(406)
Transaction, reorganization, and separation		(22)	(54)	(50)
Financing costs, net		(472)	(267)	(462)
Net income (loss) before income taxes		1,980	(4,840)	(3,008)
Total assets	18,107	14,393	12,746	18,107
Net Property and Equipment	14,158	8,060	8,819	14,158
Additions to Net Property and Equipment	2,734	1,004	1,162	2,734
Operating Segments | Egypt
Operating Expenses:
Lease operating expenses		469	424	484
Taxes other than income		0	0	0
Exploration		63	63	100
Depreciation, depletion, and amortization		524	601	708
Asset retirement obligation accretion		0	0	0
Impairments		26	529	0
Total operating expenses		1,094	1,655	1,332
Operating Income (Loss)		991	(265)	944
Other Income (Expense):
Total assets	3,700	2,796	3,003	3,700
Net Property and Equipment	2,573	1,720	1,955	2,573
Additions to Net Property and Equipment	454	319	454	454
Operating Segments | North Sea
Operating Expenses:
Lease operating expenses		383	305	320
Taxes other than income		0	0	0
Exploration		34	28	2
Depreciation, depletion, and amortization		270	380	366
Asset retirement obligation accretion		79	73	76
Impairments		22	7	0
Total operating expenses		827	843	809
Operating Income (Loss)		309	40	467
Other Income (Expense):
Total assets	2,473	2,199	2,220	2,473
Net Property and Equipment	1,956	1,646	1,773	1,956
Additions to Net Property and Equipment	183	159	215	183
Operating Segments | U.S.
Operating Expenses:
Lease operating expenses		391	400	645
Taxes other than income		190	108	194
Exploration		28	168	688
Depreciation, depletion, and amortization		554	779	1,566
Asset retirement obligation accretion		30	32	29
Impairments		0	3,963	1,648
Total operating expenses		3,077	6,095	5,211
Operating Income (Loss)		1,679	(3,937)	(2,272)
Other Income (Expense):
Total assets	10,388	7,700	5,540	10,388
Net Property and Equipment	9,385	4,507	4,760	9,385
Additions to Net Property and Equipment	1,696	523	345	1,696
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		(127)	(145)	(136)
Operating Expenses:
Lease operating expenses		(2)	(2)	(2)
Taxes other than income		0	0	0
Exploration		2	15	15
Depreciation, depletion, and amortization		0	0	0
Asset retirement obligation accretion		0	0	0
Impairments		0	0	0
Total operating expenses		(128)	(130)	(121)
Operating Income (Loss)		(2)	(15)	(15)
Other Income (Expense):
Total assets	67	0	197	67
Net Property and Equipment	38	0	135	38
Additions to Net Property and Equipment	93	0	136	93
Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		127	145	136
Operating Expenses:
Lease operating expenses		0	0	0
Taxes other than income		14	15	13
Exploration		0	0	0
Depreciation, depletion, and amortization		12	12	40
Asset retirement obligation accretion		4	4	2
Impairments		160	2	1,301
Total operating expenses		227	74	1,412
Operating Income (Loss)		(89)	75	(1,276)
Other Income (Expense):
Total assets	1,479	1,698	1,786	1,479
Net Property and Equipment	206	187	196	206
Additions to Net Property and Equipment	$ 308	3	12	308
Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		6,498	4,037	6,315
Operating Expenses:
Gathering, processing, and transmission		264	274	306
Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		2,085	1,390	2,276
Operating Expenses:
Gathering, processing, and transmission		12	38	40
Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,136	883	1,276
Operating Expenses:
Gathering, processing, and transmission		39	50	45
Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		3,280	1,764	2,763
Operating Expenses:
Gathering, processing, and transmission		309	291	299
Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		(3)
Operating Expenses:
Gathering, processing, and transmission		(128)	(143)	(134)
Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		32	38	56
Oil and gas, purchased
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,487	398	176
Operating Expenses:
Gathering, processing, and transmission		1,580	357	142
Oil and gas, purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas, purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas, purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil and gas production revenues		1,476	394	176
Operating Expenses:
Gathering, processing, and transmission		1,575	354	142
Oil and gas, purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil and gas production revenues		0	0	0
Operating Expenses:
Gathering, processing, and transmission		0	0	0
Oil and gas, purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil and gas production revenues		11	4	0
Operating Expenses:
Gathering, processing, and transmission		5	3	0
Oil and gas
Segment Reporting Information [Line Items]
Total revenues		7,985	4,435	6,491
Oil and gas | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Total revenues		2,085	1,390	2,276
Oil and gas | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Total revenues		1,136	883	1,276
Oil and gas | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Total revenues		4,756	2,158	2,939
Oil and gas | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues		(130)	(145)	(136)
Oil and gas | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Total revenues		138	149	136
Oil
Other Income (Expense):
Revenue from non-customers		420	95	410
Oil | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		4,585	3,106	5,230
Oil | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,806	1,102	1,969
Oil | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		929	795	1,163
Oil | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,850	1,209	2,098
Oil | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0
Oil | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0
Natural Gas
Other Income (Expense):
Revenue from non-customers		47	14	40
Natural Gas | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		1,207	598	678
Natural Gas | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		270	280	295
Natural Gas | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		183	67	90
Natural Gas | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		754	251	293
Natural Gas | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0
Natural Gas | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		0	0	0
Natural Gas Liquids
Other Income (Expense):
Revenue from non-customers		2	0	1
Natural Gas Liquids | Oil and gas, excluding purchased
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		706	333	407
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | Egypt
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		9	8	12
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | North Sea
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		24	21	23
Natural Gas Liquids | Oil and gas, excluding purchased | Operating Segments | U.S.
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		676	304	372
Natural Gas Liquids | Oil and gas, excluding purchased | Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		(3)	0	0
Natural Gas Liquids | Oil and gas, excluding purchased | Reportable Legal Entities | Altus Midstream
Segment Reporting Information [Line Items]
Oil, natural gas, and natural gas liquids production revenues		$ 0	$ 0	$ 0

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Asset retirement obligation accretion	$ 113	$ 109	$ 107
Lease operating expenses	1,241	1,127	1,447
Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	6,501	4,037	6,315
Depreciation, depletion, and amortization	1,255	1,643	2,512
Asset retirement obligation accretion	109	105	105
Lease operating expenses	1,243	1,129	1,449
Gathering, processing, and transmission	360	379	384
Exploration expenses	127	274	805
Impairments related to oil and gas properties		4,319	1,633
Production taxes	188	106	191
Income tax	996	(823)	175
Operating costs	4,278	7,132	7,254
Results of operations	2,223	(3,095)	(939)
United States | Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	3,280	1,764	2,763
Depreciation, depletion, and amortization	511	726	1,508
Asset retirement obligation accretion	30	32	29
Lease operating expenses	391	400	645
Gathering, processing, and transmission	309	291	299
Exploration expenses	28	168	688
Impairments related to oil and gas properties		3,938	1,633
Production taxes	188	106	191
Income tax	383	(818)	(468)
Operating costs	1,840	4,843	4,525
Results of operations	1,440	(3,079)	(1,762)
Egypt | Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,085	1,390	2,276
Depreciation, depletion, and amortization	477	540	641
Asset retirement obligation accretion	0	0	0
Lease operating expenses	469	424	484
Gathering, processing, and transmission	12	38	40
Exploration expenses	63	63	100
Impairments related to oil and gas properties		374	0
Production taxes	0	0	0
Income tax	479	(22)	455
Operating costs	1,500	1,417	1,720
Results of operations	585	(27)	556
North Sea | Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,136	883	1,276
Depreciation, depletion, and amortization	267	377	363
Asset retirement obligation accretion	79	73	76
Lease operating expenses	383	305	320
Gathering, processing, and transmission	39	50	45
Exploration expenses	34	28	2
Impairments related to oil and gas properties		7	0
Production taxes	0	0	0
Income tax	134	17	188
Operating costs	936	857	994
Results of operations	200	26	282
Other International | Oil and Gas, Exploration and Production
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	0	0	0
Depreciation, depletion, and amortization	0	0	0
Asset retirement obligation accretion	0	0	0
Lease operating expenses	0	0	0
Gathering, processing, and transmission	0	0	0
Exploration expenses	2	15	15
Impairments related to oil and gas properties		0	0
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	2	15	15
Results of operations	$ (2)	$ (15)	$ (15)

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ (157)	$ 7	$ 8
Unproved	29	4	57
Exploration	161	328	468
Development	1,085	872	1,996
Costs incurred	1,118	1,211	2,529
Capitalized interest	0	3	32
Asset retirement costs	149	38	(97)
Egypt PSC modernization impacts - Proved and Unproved	(145)
PSC modernization impacts, incremental value	247
PSC modernization impacts, signature bonus	100
PSC modernization impacts, other post closing adjustments	2
Oil and gas proved property
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
PSC modernization impacts, reduction in proved properties	165
Oil and Gas Properties, Unproved
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
PSC modernization impacts, increase in unproved properties	20
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	3
Unproved	9	4	47
Exploration	6	8	162
Development	545	332	1,500
Costs incurred	560	344	1,712
Capitalized interest	0	0	23
Asset retirement costs	130	9	14
Egypt PSC modernization impacts - Proved and Unproved	0
Egypt
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	(157)	7	5
Unproved	20	0	10
Exploration	86	102	139
Development	404	378	374
Costs incurred	353	487	528
Capitalized interest	0	0	0
Asset retirement costs	0	0	0
Egypt PSC modernization impacts - Proved and Unproved	(145)
North Sea
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration	39	68	62
Development	135	162	119
Costs incurred	174	230	181
Capitalized interest	0	0	5
Asset retirement costs	19	29	(111)
Egypt PSC modernization impacts - Proved and Unproved	0
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0	0
Unproved	0	0	0
Exploration	30	150	105
Development	1	0	3
Costs incurred	31	150	108
Capitalized interest	0	3	4
Asset retirement costs	0	$ 0	$ 0
Egypt PSC modernization impacts - Proved and Unproved	$ 0

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Reserve Quantities [Line Items]
Proved properties	$ 40,059	$ 41,217
Unproved properties	415	602
Capitalized costs, gross	40,474	41,819
Accumulated DD&A	(32,926)	(33,623)
Capitalized costs, net	7,548	8,196
United States
Reserve Quantities [Line Items]
Proved properties	18,732	20,343
Unproved properties	319	348
Capitalized costs, gross	19,051	20,691
Accumulated DD&A	(14,814)	(16,252)
Capitalized costs, net	4,237	4,439
Egypt
Reserve Quantities [Line Items]
Proved properties	12,373	12,069
Unproved properties	63	77
Capitalized costs, gross	12,436	12,146
Accumulated DD&A	(10,767)	(10,290)
Capitalized costs, net	1,669	1,856
North Sea
Reserve Quantities [Line Items]
Proved properties	8,954	8,805
Unproved properties	33	42
Capitalized costs, gross	8,987	8,847
Accumulated DD&A	(7,345)	(7,081)
Capitalized costs, net	1,642	1,766
Other International
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	0	135
Capitalized costs, gross	0	135
Accumulated DD&A	0	0
Capitalized costs, net	$ 0	$ 135

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2021 MBoe MMcf MBbls	Dec. 31, 2020 MBoe MBbls MMcf	Dec. 31, 2019 MBoe MBbls MMcf	Dec. 31, 2018 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Proved developed reserves	827,772	797,843	892,816	1,081,316
Proved undeveloped reserves	85,190	75,840	117,972	153,081
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	873,683	1,010,788	1,234,397
Extensions, discoveries and other additions	101,619	78,303	176,366
Purchases of minerals in-place	457
Revisions of previous estimates	107,038	(44,910)	(119,473)
Production	(141,642)	(160,945)	(172,948)
Sales of minerals in-place	(28,193)	(9,553)	(107,554)
Ending balance	912,962	873,683	1,010,788
United States
Reserve Quantities [Line Items]
Proved developed reserves	551,384	532,994	594,595	769,125
Proved undeveloped reserves	65,288	53,408	89,458	123,493
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	586,402	684,053	892,618
Extensions, discoveries and other additions	76,871	39,454	135,174
Purchases of minerals in-place	457
Revisions of previous estimates	64,847	(33,854)	(133,974)
Production	(83,712)	(93,698)	(102,211)
Sales of minerals in-place	(28,193)	(9,553)	(107,554)
Ending balance	616,672	586,402	684,053
Egypt
Reserve Quantities [Line Items]
Proved developed reserves	184,563	164,870	176,470	189,871
Proved undeveloped reserves	12,683	13,449	15,038	15,045
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	178,319	191,508	204,916
Extensions, discoveries and other additions	21,765	31,905	26,859
Purchases of minerals in-place	0
Revisions of previous estimates	39,071	(502)	8,355
Production	(41,909)	(44,592)	(48,622)
Sales of minerals in-place	0	0	0
Ending balance	197,246	178,319	191,508
North Sea
Reserve Quantities [Line Items]
Proved developed reserves	91,825	99,979	121,751	122,320
Proved undeveloped reserves	7,219	8,983	13,476	14,543
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	108,962	135,227	136,863
Extensions, discoveries and other additions	2,983	6,944	14,333
Purchases of minerals in-place	0
Revisions of previous estimates	3,120	(10,554)	6,146
Production	(16,021)	(22,655)	(22,115)
Sales of minerals in-place	0	0	0
Ending balance	99,044	108,962	135,227
Noncontrolling Interests | Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) | MBoe	66	59	64	68
Crude Oil and Condensate
Reserve Quantities [Line Items]
Proved developed reserves	364,687	389,483	483,430	514,989
Proved undeveloped reserves	34,928	44,017	67,596	65,944
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	433,500	551,026	580,933
Extensions, discoveries and other additions	33,547	40,988	82,353
Purchases of minerals in-place	126
Revisions of previous estimates	18,188	(71,462)	(6,562)
Production	(66,364)	(78,331)	(87,386)
Sales of minerals in-place	(19,382)	(8,721)	(18,312)
Ending balance	399,615	433,500	551,026
Crude Oil and Condensate | United States
Reserve Quantities [Line Items]
Proved developed reserves	180,968	206,936	278,145	300,484
Proved undeveloped reserves	18,168	25,516	46,716	45,182
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	232,452	324,861	345,666
Extensions, discoveries and other additions	17,869	17,858	52,297
Purchases of minerals in-place	126
Revisions of previous estimates	(4,479)	(69,247)	(16,446)
Production	(27,450)	(32,299)	(38,344)
Sales of minerals in-place	(19,382)	(8,721)	(18,312)
Ending balance	199,136	232,452	324,861
Crude Oil and Condensate | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	106,646	95,981	103,573	110,014
Proved undeveloped reserves	11,003	11,228	10,831	9,484
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	107,209	114,404	119,498
Extensions, discoveries and other additions	13,390	17,855	21,039
Purchases of minerals in-place	0
Revisions of previous estimates	22,727	2,541	4,752
Production	(25,677)	(27,591)	(30,885)
Sales of minerals in-place	0	0	0
Ending balance	117,649	107,209	114,404
Crude Oil and Condensate | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	77,073	86,566	101,712	104,491
Proved undeveloped reserves	5,757	7,273	10,049	11,278
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	93,839	111,761	115,769
Extensions, discoveries and other additions	2,288	5,275	9,017
Purchases of minerals in-place	0
Revisions of previous estimates	(60)	(4,756)	5,132
Production	(13,237)	(18,441)	(18,157)
Sales of minerals in-place	0	0	0
Ending balance	82,830	93,839	111,761
Crude Oil and Condensate | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	39,000	36,000	38,000	40,000
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved developed reserves	166,677	153,368	161,778	200,014
Proved undeveloped reserves	16,685	15,587	24,319	34,487
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	168,955	186,097	234,501
Extensions, discoveries and other additions	21,143	11,844	42,067
Purchases of minerals in-place	191
Revisions of previous estimates	22,862	(412)	(31,716)
Production	(24,806)	(28,118)	(25,933)
Sales of minerals in-place	(4,983)	(456)	(32,822)
Ending balance	183,362	168,955	186,097
Natural Gas Liquids | United States
Reserve Quantities [Line Items]
Proved developed reserves	164,172	150,599	158,794	197,574
Proved undeveloped reserves	16,380	15,141	23,569	33,796
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	165,740	182,363	231,370
Extensions, discoveries and other additions	21,055	11,435	41,343
Purchases of minerals in-place	191
Revisions of previous estimates	22,724	(469)	(32,569)
Production	(24,175)	(27,133)	(24,959)
Sales of minerals in-place	(4,983)	(456)	(32,822)
Ending balance	180,552	165,740	182,363
Natural Gas Liquids | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	446	716	667	502
Proved undeveloped reserves	30	126	90	60
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	842	757	562
Extensions, discoveries and other additions	7	97	27
Purchases of minerals in-place	0
Revisions of previous estimates	(180)	264	508
Production	(193)	(276)	(340)
Sales of minerals in-place	0	0	0
Ending balance	476	842	757
Natural Gas Liquids | North Sea
Reserve Quantities [Line Items]
Proved developed reserves	2,059	2,053	2,317	1,938
Proved undeveloped reserves	275	320	660	631
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	2,373	2,977	2,569
Extensions, discoveries and other additions	81	312	697
Purchases of minerals in-place	0
Revisions of previous estimates	318	(207)	345
Production	(438)	(709)	(634)
Sales of minerals in-place	0	0	0
Ending balance	2,334	2,373	2,977
Natural Gas Liquids | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves	159	281	252	187
Natural Gas
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,778,442	1,529,950	1,485,649	2,197,882
Proved undeveloped reserves | MMcf	201,464	97,417	156,348	315,900
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,627,367	1,641,997	2,513,782
Extensions, discoveries and other additions | MMcf	281,577	152,823	311,674
Purchases of minerals in-place | MMcf	839
Revisions of previous estimates | MMcf	395,924	161,776	(487,168)
Production | MMcf	(302,833)	(326,974)	(357,771)
Sales of minerals in-place | MMcf	(22,968)	(2,255)	(338,520)
Ending balance | MMcf	1,979,906	1,627,367	1,641,997
Natural Gas | United States
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,237,461	1,052,756	945,938	1,626,403
Proved undeveloped reserves | MMcf	184,441	76,504	115,040	267,090
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	1,129,260	1,060,978	1,893,493
Extensions, discoveries and other additions | MMcf	227,684	60,965	249,205
Purchases of minerals in-place | MMcf	839
Revisions of previous estimates | MMcf	279,610	215,166	(509,753)
Production | MMcf	(192,523)	(205,594)	(233,447)
Sales of minerals in-place | MMcf	(22,968)	(2,255)	(338,520)
Ending balance | MMcf	1,421,902	1,129,260	1,060,978
Natural Gas | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	464,826	409,035	433,382	476,132
Proved undeveloped reserves | MMcf	9,899	12,572	24,704	33,006
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	421,607	458,086	509,138
Extensions, discoveries and other additions | MMcf	50,209	83,718	34,758
Purchases of minerals in-place	0
Revisions of previous estimates	99,143	(19,849)	18,570
Production	(96,234)	(100,348)	(104,380)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	474,725	421,607	458,086
Natural Gas | North Sea
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	76,155	68,159	106,329	95,347
Proved undeveloped reserves | MMcf	7,124	8,341	16,604	15,804
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance | MMcf	76,500	122,933	111,151
Extensions, discoveries and other additions | MMcf	3,684	8,140	27,711
Purchases of minerals in-place	0
Revisions of previous estimates	17,171	(33,541)	4,015
Production	(14,076)	(21,032)	(19,944)
Sales of minerals in-place	0	0	0
Ending balance | MMcf	83,279	76,500	122,933
Natural Gas | Noncontrolling Interests | Egypt
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	158,000	141,000	153,000	170,000

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) MBoe in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2021 MBoe	Dec. 31, 2020 MBoe	Dec. 31, 2019 MBoe
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		102	78,000	176
Revision of previous estimate		107	45,000	(119)
PSCs, discounted future net cash flows | $	$ 750
PSCs, percentage of reserves consolidated	96.00%
Percentage of estimated proved developed reserves classified as proved not producing		12.00%
North America
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		77	39,000	135
Southern Midland Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions			26,000
International Regions
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		25	39,000	41
Egypt
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		22	32,000	27
North Sea
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		3	7,000	14
Eastern Shelf and Magnet Withers/Pickett Ridge
Reserve Quantities [Line Items]
Sale of mineral in place		28	10,000
Anadarko Basin
Reserve Quantities [Line Items]
Sale of mineral in place				107
Premian Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions				129
MidContinent Region
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions				6
Permian Basin
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		59
Texas Gulf Coast
Reserve Quantities [Line Items]
Addition from extensions, discoveries, and other additions		18
Changes in Product Prices
Reserve Quantities [Line Items]
Revision of previous estimate		85	70,000	(139)
Changes in Engineering and Performance
Reserve Quantities [Line Items]
Revision of previous estimate		22	27,000	20
Interest Revisions
Reserve Quantities [Line Items]
Revision of previous estimate			(2)
Production Sharing Contracts Modernization Impact
Reserve Quantities [Line Items]
Revision of previous estimate		57
Other Revisions
Reserve Quantities [Line Items]
Revision of previous estimate		(35)
Production Sharing Contracts Modernization Impact, Developed Reserves
Reserve Quantities [Line Items]
Revision of previous estimate		53
Production Sharing Contracts Modernization Impact, Undeveloped Reserves
Reserve Quantities [Line Items]
Revision of previous estimate		4

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 39,021	$ 22,219	$ 37,454
Production costs	(12,378)	(10,336)	(15,219)
Development costs	(5,567)	(4,636)	(5,098)
Income tax expense	(2,789)	(780)	(2,741)
Net cash flows	18,287	6,467	14,396
10 percent discount rate	(5,927)	(1,155)	(4,514)
Discounted future net cash flows	$ 12,360	5,312	9,882
Estimated future net cash flow before income tax expenses	10.00%
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum	$ 15,300	7,100	12,400
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	22,852	12,537	21,694
Production costs	(8,323)	(6,244)	(10,642)
Development costs	(1,632)	(1,555)	(1,740)
Income tax expense	(134)	0	(27)
Net cash flows	12,763	4,738	9,285
10 percent discount rate	(5,294)	(1,829)	(4,003)
Discounted future net cash flows	7,469	2,909	5,282
Egypt
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	9,337	5,560	8,306
Production costs	(1,712)	(1,704)	(1,847)
Development costs	(1,402)	(633)	(707)
Income tax expense	(1,887)	(1,096)	(1,930)
Net cash flows	4,336	2,127	3,822
10 percent discount rate	(983)	(437)	(808)
Discounted future net cash flows	3,353	1,690	3,014
Egypt | Noncontrolling Interests
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	1,100	563	1,000
North Sea
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	6,832	4,122	7,454
Production costs	(2,343)	(2,388)	(2,730)
Development costs	(2,533)	(2,448)	(2,651)
Income tax expense	(768)	316	(784)
Net cash flows	1,188	(398)	1,289
10 percent discount rate	350	1,111	297
Discounted future net cash flows	$ 1,538	$ 713	$ 1,586

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Sales, net of production costs	$ (4,707)	$ (2,422)	$ (4,291)
Net change in prices and production costs	9,376	(5,753)	(3,034)
Discoveries and improved recovery, net of related costs	1,749	751	2,042
Change in future development costs	(839)	20	(75)
Previously estimated development costs incurred during the period	545	576	983
Revision of quantities	1,983	(418)	(741)
Purchases of minerals in-place	1	0	0
Accretion of discount	626	1,236	1,693
Change in income taxes	(1,583)	1,533	720
Sales of minerals in-place	(116)	(104)	(817)
Change in production rates and other	13	11	(319)
Change in the discounted future net cash flows, Total	$ 7,048	$ (4,570)	$ (3,839)