apa-20201231

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, 2020


☐			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:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.625 par value	APA	Nasdaq Global Select Market

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 ☐

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, 2020	$	5,095,687,766
Number of shares of registrant’s common stock outstanding as of January 29, 2021	377,860,971

Documents Incorporated By Reference

Portions of the registrant’s definitive proxy statement relating to the registrant’s 2021 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.

On January 4, 2021, the registrant (Apache) announced that its Board of Directors authorized Apache to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be

the successor issuer to Apache pursuant to Rule 12g-3(a) under the Securities Exchange Act of 1934, as amended, and APA will replace Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA”. If the holding company reorganization is completed prior to the date that Apache’s definitive proxy statement relating to the 2021 annual meeting of stockholders is filed with the Securities and Exchange Commission, then the definitive proxy statement will be filed by APA, as successor issuer to Apache.

TABLE OF CONTENTS


Item		Page

	PART I

1.	BUSINESS	1
1A.	RISK FACTORS	18
1B.	UNRESOLVED STAFF COMMENTS	30
2.	PROPERTIES	1
3.	LEGAL PROCEEDINGS	30
4.	MINE SAFETY DISCLOSURES	30

	PART II

5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	31
6.	SELECTED FINANCIAL DATA	32
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	55
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	55
9A.	CONTROLS AND PROCEDURES	56
9B.	OTHER INFORMATION	56

	PART III

10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	57
11.	EXECUTIVE COMPENSATION	57
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	57
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	57
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	57

	PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	58
16.	FORM 10-K SUMMARY	62

FORWARD-LOOKING STATEMENTS AND RISK

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2020, and other data in the Company’s possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue,” “seek,” “guidance,” “might,” “outlook,” “possibly,” “potential,” “prospect,” “should,” “would,” or similar terminology, but the absence of these words does not mean that a statement is not forward looking. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable under the circumstances, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, its assumptions about:

•the scope, duration, and reoccurrence of any epidemics or pandemics (including, specifically, the coronavirus disease 2019 (COVID-19) pandemic) and 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 market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

•the Company’s commodity hedging arrangements;

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

•production and reserve levels;

•drilling risks;

•economic and competitive conditions;

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the availability of goods and services;

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

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

•terrorism or cyberattacks;

•the occurrence of property acquisitions or divestitures;

•the integration of acquisitions;

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

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

•the Company’s expectations with respect to the new operating structure anticipated to be implemented pursuant to the announced holding company reorganization described in this Annual Report on Form 10-K and the associated disclosure implications; and

•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 or 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.

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 in herein:

“3-D” means three-dimensional.

“4-D” means four-dimensional.

“b/d” means barrels of oil or natural gas liquids per day.

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

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

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

“boe/d” means boe per day.

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

“Liquids” means oil and natural gas liquids.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

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

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

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

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

References to “Apache,” the “Company,” “we,” “us,” and “our” refer to Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.

iii

PART I


ITEMS 1 and 2.			BUSINESS AND PROPERTIES

GENERAL

Apache Corporation, a Delaware corporation formed in 1954, 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 also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

On January 4, 2021, Apache announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act, and APA will replace Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA” (the Holding Company Reorganization). The Holding Company Reorganization has not yet been implemented, but it is expected to be completed during the first half of 2021. Further details of the planned Holding Company Reorganization are included in the Company’s Current Report on Form 8-K filed with the SEC on January 4, 2021.

The Company’s common stock, par value $0.625 per share, is listed on the Nasdaq Global Select Market (Nasdaq). Through the Company’s website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of its Board of Directors, other documents related to corporate governance (including the Code of Business Conduct and Ethics and Apache’s Corporate Governance Principles), and 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 filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act. 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, committee charters, or other governance documents free of charge by writing to the Company’s corporate secretary at the address on the cover of this report. The Company’s reports filed with the SEC are made available on its website at www.sec.gov. From time to time, the Company also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on the Company’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 STRATEGY

Our VISION is to be the premier exploration and production company, contributing to global progress by helping meet the world’s energy needs.

Our MISSION is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of our stakeholders.

Our STRATEGY is to take a differentiated approach to the exploration and production of cost-advantaged hydrocarbons through innovation, technology, optimization, continuous improvement, and relentless focus on costs to deliver top-tier, long-term returns.

Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, Apache has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. These efforts included the monetization of certain non-strategic assets, including gas-weighted properties in the Midcontinent/Gulf Coast region and selling other non-core leasehold positions. The Company made strategic decisions to allocate the proceeds of these divestitures to more impactful development opportunities across its portfolio and exploration efforts in Suriname. In addition, in November 2018, the Company completed a transaction with Altus Midstream Company and its then wholly-owned subsidiary, Altus Midstream LP, to create a publicly-traded midstream C-corporation.

Apache’s U.S. upstream oil and gas assets are complemented by its international assets in Egypt and the North Sea, each of which adds to the Company’s inventory of exploration and development opportunities. Apache’s diverse international portfolio and asset inventory includes, at scale, both conventional and unconventional resources covering crude oil, rich natural gas with NGLs, and lean natural gas.

During 2020, the global economy and the energy industry were deeply impacted by the effects of the COVID-19 pandemic and related third-party actions. Uncertainty in the oil markets and the negative demand implications resulting from the COVID-19 pandemic continue to weigh on commodity prices. As with previous changes in a volatile price environment, Apache has continued to respond quickly and decisively, taking the following strategic actions:

•Establishing and implementing a wide range of fit-for-purpose protocols and procedures to ensure a safe and productive work environment across the Company’s diversified global onshore and offshore operations.

•Reducing upstream capital investments by over 50 percent from the comparative prior-year period, including eliminating nearly all U.S. drilling and completion activity by May 2020 and reducing planned activity in Egypt and the North Sea.

•Decreasing the Company’s dividend by 90 percent beginning in the first quarter of 2020, preserving approximately $340 million of cash flow on an annualized basis and strengthening liquidity.

•Completing an organizational redesign focused on centralizing certain operational activities in an effort to capture greater efficiencies, achieving an estimated cost savings of $400 million annually.

•Conducting, on a continuous basis, price sensitivity analyses and operational evaluations of producing wells across the Company’s portfolio that allow for a methodical and integrated approach to production shut-ins and curtailments with a focus on preserving cash flows in a distressed price environment and protecting the Company’s assets.

For a more in-depth discussion of the Company’s 2020 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

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 the North Sea. Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. During 2020, as a result of the Company’s organizational redesign, Apache shifted from a region-based structure to a centralized structure focused on core asset groups and functions in each country.

The following table sets out a brief comparative summary of certain key 2020 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.


	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	93.7	58	%	$	1,764	587	67	%	60	59
Egypt(1)	44.6	28	%	1,390		178	20	%	61	54
North Sea(2)	22.6	14	%	883		109	13	%	8	6
Other International	—	—		—		—	—		3	—
Total	160.9	100	%	$	4,037	874	100	%	132	119

(1)Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 20 percent of 2020 production and accounted for 15 percent of year-end estimated proved reserves.

(2)Sales volumes from the North Sea for 2020 were 22.7 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

United States

In 2020, Apache’s U.S. upstream oil and gas operations contributed approximately 58 percent of production and 67 percent of estimated year-end proved reserves. Apache has access to significant liquid hydrocarbons across its 4.9 million gross acres (2.5 million net acres) in the U.S., 78 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 more than 7,000 gross oil and gas wells across its acreage, with additional interests in over 4,000 non-operated wells. 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 and along the Gulf of Mexico, in the areas onshore and offshore south Texas and Louisiana.

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

•Southern Midland Basin Apache holds approximately 360,000 gross acres (256,000 net acres) in the Southern Midland Basin. The Company began the year operating four rigs but suspended drilling and completion activity in May in response to collapsing commodity prices. During 2020, the Company averaged one rig targeting oil plays in the Wolfcamp, Spraberry, and lower Cline formations, drilling 33 gross development wells in this basin with a 100 percent success rate.

•Delaware Basin Apache holds approximately 370,000 gross acres (220,000 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. The Company began the year operating three rigs but suspended drilling in May. During 2020, the Company averaged one rig drilling 19 gross development wells with a 95 percent success rate, primarily targeting oil plays in the Bone Spring formation.

•Legacy Assets Apache holds approximately 3.6 million gross acres (1.7 million net acres) in legacy properties, primarily in the Central Basin Platform sub-basin of the Permian Basin, the Eagle Ford shale and Austin Chalk areas of southeast Texas, and in the offshore waters of the Gulf of Mexico and onshore Louisiana. The Company participated in drilling eight gross non-operated development wells in these areas during 2020. Although operated drilling activity was minimal during 2020, the Company continued to evaluate and high-grade inventory opportunities on its Austin Chalk acreage. The Company also monetized certain non-strategic leasehold positions on its legacy acreage holdings during the year and is continuing to evaluate additional opportunities.

•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.

With the improvement in oil prices, the Company is returning to a modest level of activity in the U.S. For 2021, the Company is currently running one drilling rig in the Permian Basin and plans to add a second rig in the middle of the year. In addition, the Company recently added a rig in the Austin Chalk oil play to retain core acreage positions and perform targeted tests. The Company also resumed completions activity in the Permian Basin during the fourth quarter of 2020 and began completing previously drilled but uncompleted wells in response to significantly lower service costs. As with prior periods, the Company will continue to monitor commodity prices and will adjust its capital budget accordingly to protect its cash flows.

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 United States, including to U.S. LNG export facilities, although a portion is 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, which require Apache to deliver an average of 232 Bcf of natural gas per year for the period from 2021 through 2029 at variable, market-based pricing and deliver an average of 6.8 MMbbls of crude oil per year from 2020 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 2020, international assets contributed 42 percent of Apache’s production and 56 percent of oil and gas revenues. Approximately 33 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 United Kingdom.

The Company also has an active offshore exploration program and planned appraisal operations ongoing in Suriname.

Egypt Apache has 25 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 2020, the Company held 5.2 million gross acres in 24 separate concessions. 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.

Apache’s Egypt operations are conducted pursuant to production sharing contracts (PSCs). Under the terms of the Company’s PSCs, the contractor partner (Contractor) 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 Egyptian General Petroleum Corporation (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 Apache’s Egypt operations despite impacting Apache’s production and reserves.

The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. In addition, Sinopec International Petroleum Exploration and Production Corporation (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 28 percent of 2020 production and 20 percent of year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 20 percent of 2020 production and 15 percent of year-end estimated proved reserves.

In 2020, the Company drilled 36 gross development and 25 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 2021, the Company plans to continue running a five rig drilling program for the year with a goal of stabilizing production and ultimately return Egypt to growth, both of which would require additional rigs. Apache is positioned to quickly flex spending in Egypt as conditions warrant and will continue to monitor oil prices and cash flow for the appropriate time to pursue increased activity.

North Sea Apache has interests in approximately 516,000 gross acres in the U.K. North Sea. These assets contributed 14 percent of Apache’s 2020 production and approximately 13 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 the 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 plays 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 2020, Apache averaged two rigs in the North Sea and drilled 6 gross development and two gross exploration wells.

The Company’s Storr exploration discovery came on-line in the fourth quarter of 2019, and its second well at Garten came on-line in the first quarter of 2020. The first well at the Company’s Storr development is a high-rate gas condensate well that is tied back to existing infrastructure at the Beryl Alpha platform. The Garten #2 well encountered approximately 1,200 feet of net pay, and Apache holds a 100 percent working interest in the Garten complex. Both of these exploration discoveries coming on-line, coupled with the modest drilling activity level for the year, increased the Company’s production in the North Sea compared to 2019.

In 2021, the expected capital program for the North Sea remains relatively unchanged to the prior year with one floating rig and one platform crew.

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.

Other Exploration

New Ventures Apache’s international New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins.

In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. The Company holds a 50 percent working interest in Block 58, which comprises approximately 1.4 million gross acres in water depths ranging from less than 100 meters to more than 2,100 meters. Starting in late 2019 and throughout 2020, Apache drilled the first three wells in the block, the Maka Central-1, Sapakara West-1, and Kwaskwasi-1, all of which successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals, encountering both oil and gas condensate.

In January 2021, Apache and Total S.A announced the fourth consecutive discovery in Block 58 at Keskesi East-1, which confirmed oil in the eastern portion of the block. The Keskesi East-1 well is continuing to drill to deeper targets. In accordance with the joint venture agreement, Apache transferred operatorship of Block 58 to Total S.A. on January 1, 2021. Apache will continue to operate the Keskesi exploration well until completion of drilling operations.

Drilling Statistics

Worldwide in 2020, Apache drilled or participated in drilling 132 gross wells, with 119 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: 80 gross (63.1 net) in the U.S., 24 gross (23.5 net) in Egypt, 1 gross (1 net) in the North Sea, and 1 gross (0.5 net) in Suriname.

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
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
2018
United States	47.6	5.3	52.9	188.9	2.0	190.9	236.5	7.3	243.8
Egypt	28.2	12.5	40.7	57.9	0.5	58.4	86.1	13.0	99.1
North Sea	1.0	0.5	1.5	6.3	—	6.3	7.3	0.5	7.8

Total	76.8	18.3	95.1	253.1	2.5	255.6	329.9	20.8	350.7

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, 2020, is set forth below:


	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	11,377	6,627	1,135	799	12,512	7,426
Egypt	1,069	1,015	111	108	1,180	1,123
North Sea	163	122	12	7	175	129
Total	12,609	7,764	1,258	914	13,867	8,678

Domestic	11,377	6,627	1,135	799	12,512	7,426
Foreign	1,232	1,137	123	115	1,355	1,252
Total	12,609	7,764	1,258	914	13,867	8,678

Gross natural gas and crude oil wells include 558 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)
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
2018
United States	38.3	21.0	216.5	$	10.01	$	59.36	$	26.28	$	2.12
Egypt(1)	34.2	0.3	119.3	8.71		70.09		39.17		2.84
North Sea(2)	17.1	0.4	16.6	18.92		69.02		45.84		7.33
Total	89.6	21.7	352.4	10.66		65.30		26.87		2.61

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

(2)Sales volumes from the North Sea for 2020, 2019, and 2018 were 22.7 MMboe, 21.8 MMboe, and 20.3 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, 2020:


	Undeveloped Acreage		Developed Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres
	(In thousands)
United States	3,818	1,808	1,064	656
Egypt	3,495	3,495	1,658	1,569
North Sea	331	301	185	139
Other International	2,308	1,111	—	—
Total	9,952	6,715	2,907	2,364

As of December 31, 2020, approximately 46 percent of U.S. net undeveloped acreage was held by production.

As of December 31, 2020, Apache held 1.5 million net undeveloped acres that are scheduled to expire by year-end 2021 if production is not established or the Company takes no action to extend the terms. The Company also held 533,000 and 408,000 net undeveloped acres set to expire by year-end 2022 and 2023, 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.

Exploration concessions in the Company’s Egypt asset comprise a significant portion of its expiring net undeveloped acreage, with approximately 1.3 million, 74,000 and 343,000 net undeveloped acres set to expire during 2021, 2022, and 2023, respectively. No oil and gas reserves were recorded on this undeveloped acreage set to expire. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist.

Additionally, the Company has exploration interests in Suriname consisting of 390,000 net undeveloped acres in Block 53 set to expire in 2022 contingent on planned drilling activity. The Company has acquired 3-D seismic surveys over all acreages. No oil and gas reserves have been recorded on this undeveloped acreage.

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.

The following table shows proved oil, NGL, and gas reserves as of December 31, 2020, based on average commodity prices in effect on the first day of each month in 2020, 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	207	151	1,053	533
Egypt(1)	96	1	409	165
North Sea	87	2	68	100
Total	390	154	1,530	798
Proved Undeveloped:
United States	26	15	76	54
Egypt(1)	11	—	13	13
North Sea	7	—	8	9
Total	44	15	97	76
Total Proved	434	169	1,627	874

(1)Includes total proved developed and total proved undeveloped reserves of 55 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.

As of December 31, 2020, Apache had total estimated proved reserves of 434 MMbbls of crude oil, 169 MMbbls of NGLs, and 1.6 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 874 million barrels of oil or 5.2 Tcf of natural gas, of which oil represents 50 percent. As of December 31, 2020, the Company’s proved developed reserves totaled 798 MMboe and estimated PUD reserves totaled 76 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 does not have any fields that contain 15 percent or more of its total proved reserves for the years ended December 31, 2020, 2019, and 2018.

During 2020, the Company added 78 MMboe of proved reserves through exploration and development activity, partially offset by combined downward revisions of previously estimated reserves of 45 MMboe. Engineering and performance upward revisions accounted for 27 MMboe and downward revisions related to changes in product prices and interest accounted for (70) MMboe and 2 MMboe, respectively. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge.

The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2020, 2019, and 2018, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18—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.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 76 MMboe as of December 31, 2020, decreased by 42 MMboe from 118 MMboe of PUD reserves reported at the end of 2019. During the year, Apache converted 35 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 25 MMboe, with the remaining 10 MMboe in Apache’s international areas. Apache did not sell any PUD reserves in the U.S. and did not acquire any PUD reserves during the year. Apache added 43 MMboe of new PUD reserves through extensions and discoveries. Apache did not recognize an upward engineering revision in proved undeveloped reserves during the year. Downward revisions included 1 MMboe associated with engineering and interest revisions, 43 MMboe associated with revised development plans, and 6 MMboe associated with product prices.

During the year, a total of approximately $339 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 2020, Apache spent approximately $251 million on PUD reserve development activity in the U.S. and $88 million in the international areas. As of December 31, 2020, 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 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 our processes and the reasonableness of our 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 2020, the properties selected for each country ranged from 84 to 86 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 84 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 81 percent of total proved reserves on a boe basis.

Ryder Scott’s review for the years 2020, 2019, and 2018 covered 85, 87, and 86 percent, respectively, of the value and 81, 85, and 83 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2020 review covered 80, 82, and 83 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.

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.

Ryder Scott’s review of 2018 covered 82 percent of U.S., 85 percent of Egypt, and 81 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.

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 completed a transaction with Altus Midstream Company and its then wholly-owned subsidiary Altus Midstream LP (collectively, Altus) 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 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 received economic voting and non-economic voting shares in Altus Midstream Company 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.

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, 2020, 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, Midland, Hobson, 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 February 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 in the commissioning phase and flowing partial volumes as of December 31, 2020 and 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.

Salt Creek NGL Pipeline Altus Midstream LP’s subsidiary’s final Pipeline Option to acquire a 50 percent equity interest in the Salt Creek NGL Pipeline, an intra-basin NGL pipeline, was not exercised and expired on March 2, 2020.

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 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. During 2018, sales to BP, Sinopec, and EGPC, and their respective affiliates, each accounted for approximately 17 percent, 15 percent, and 10 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.

HUMAN CAPITAL MANAGEMENT

As a company, Apache believes its people are its greatest asset. Exploring what’s possible at Apache is the union of curiosity, intellect, and hard work, built on mutual respect, honesty, integrity, and a keen sense of responsibility for the Company’s team, community, and the environment. With respect to its employees, the Company is focused on health and safety, diversity and inclusion, and total rewards, so that joining the Apache family is a positive experience for all.

In 2020, a major redesign of Apache’s organizational structure and operations and the global COVID-19 pandemic had significant impacts on the Company’s human capital management. In connection with the organizational and operational redesign and changes in the economic environment in which Apache operates, the Company offered voluntary retirement packages, made reductions-in-force, and began limiting hiring to critical business roles. In response to the global COVID-19 pandemic, Apache implemented significant operating environment changes that the Company determined were in the best interest of its employees and complied with government regulations. These changes include having the vast majority of Apache’s employees working from home, while implementing additional safety protocols and procedures for essential employees continuing critical on-site work.

Oversight and Management

Apache’s Board of Directors has three standing committees, each devoted to a separate aspect of risk oversight. The Corporate Governance and Nominating (CG&N) Committee, the Audit Committee, the Management Development and Compensation (MD&C) Committee, and/or the full Board of Directors receive regular reports on certain human capital matters, including the Company’s diversity and inclusion programs and initiatives.

•The MD&C Committee oversees Apache's compensation programs, leadership development and succession planning strategies, and seeks continuous improvement in the diversity and inclusion practices used in developing and deploying these processes.

•The Audit Committee oversees the integrity of the Company's financial statements and monitors human capital management risk against compliance with legal and regulatory requirements.

•The CG&N Committee oversees the nomination of candidates for election to the Board of Directors, the annual Board of Directors evaluation process, corporate governance and environmental, social, and governance (ESG) issues, as well as the Company’s annual sustainability report.

Reports and recommendations made to the Board of Directors and its committees are part of the framework that ensures the Company’s daily actions and decisions are guided by its core values, including upholding the health and safety of Apache’s team, stakeholders, and communities, investing in its workforce, ensuring environmental responsibility, and acting ethically and with integrity.

COVID-19 Response

During the early stages of the pandemic, Apache called upon its Crisis Management Team to lead and coordinate the Company's overall COVID-19 pandemic response. This team led efforts to develop and monitor mitigation and business continuity plans, track all relevant country, state and local government guidelines, directives and regulations, develop and adopt work-from-home plans, implement safe working protocols for production teams, assess and implement appropriate return-to-office protocols, and provide timely and transparent communications to global employees and key stakeholders.

In response to the COVID-19 pandemic, Apache began providing the following benefits to its employees:

•Covering the cost of COVID-19 testing at the Company’s onsite testing events and through expanded insurance coverage;

•Expanding telehealth benefits;

•Promoting mental health and well-being plans;

•Implementing enhanced hardship distributions and loan eligibility and repayment terms in the Apache 401(k) Savings Plan; and

•Providing additional paid sick leave for quarantined employees.

Employee Profile

As of December 31, 2020, Apache had approximately 2,272 full-time equivalent employees in locations across the organization as follows:


						Employees
United States						1,430
United Kingdom						598
Egypt						237
Suriname						7
Total employees						2,272

The employment of approximately 637 employees globally were impacted by involuntary reductions-in-force in 2020. The impacted employees were provided severance packages that included Company-paid benefits and outplacement services. The voluntary workforce turnover for 2020 was 9.6 percent.

As of year-end 2020, Apache’s global workforce was 22.1 percent female and 77.9 percent male, and women represented 17.6 percent of leadership (defined as supervisor level and above or equivalent). In the U.S., Apache’s workforce self-identified as 66.9 percent White, 6 percent Black, 6.8 percent Asian, 18.6 percent Hispanic, and 1.7 percent other. For the Company’s U.S. leadership, the breakdown was 78 percent White, 3 percent Black, 6.3 percent Asian, 11.3 percent Hispanic, and 1.4 percent other.

Health and Safety

Safety underpins the Company’s core values and is at the forefront of decision-making at every level of the Apache organization. Apache is committed to driving a safety culture that empowers its team to act as needed to work safely and to stop the job if conditions are deemed unsafe. Apache’s goal is to demonstrate a continual reduction in Occupational Safety and Health Administration (OSHA) recordable incidents year over year. To this end, the Company’s annual OSHA recordable incident rate targets are set at a 10 percent reduction compared to the preceding 3-year average. During the fiscal year ended December 31, 2020, the recordable incident count for the Company declined by 21 percent compared to the fiscal year ended December 31, 2019.

Apache offers a wide range of training programs for employees and contractors to promote their full understanding of, and compliance with, the Company’s health and safety policies and programs and to help build the skills needed to work safely. In addition to providing specific skills, these training programs encourage personal responsibility for safe operating conditions and help build a culture of individual accountability for conducting job tasks in a safe and responsible manner.

A few key highlights from 2020:

•Egypt From drilling to driving, safe-work behavior improved dramatically. The joint-venture drilling team had 55 percent fewer injuries in the second half of 2020 as compared to the first half of 2020.

•Suriname With the complexities of working during the pandemic, stringent health and safety protocols have kept personnel safe as they rotate offshore. Rewarding excellence, the drilling team and Noble Sam Croft drillship achieved one year without any recordable incidents.

•U.K. In an effort to connect teams with management, Apache’s elected safety representatives have increased workforce engagement around offshore operations and safety. New platform meetings put safety at the forefront of conversations about performance, accidents and hazards, industry updates, and valuable topics such as mental health.

•U.S. Despite economic pressures and pandemic challenges, U.S. onshore operations and asset teams performed exceptionally. The Southern Midland Basin, Legacy, and Delaware Basin collectively achieved over 800 days without injuries.

Diversity and Inclusion

Diversity and inclusion (D&I) are vital to Apache’s long-term sustainability. The Company is committed to being a workplace where all employees are valued and can thrive with a sense of belonging, not just as an employee, but as a person. This benefits the individual, Apache and the Company’s stakeholders. Apache is better as an organization when various ideas and perspectives are brought to the table. As a part of the Company’s commitment to diversity and inclusion, in August 2020, Apache hired a D&I Lead and partnered with a prominent D&I consultant to better understand where the organization stands in its D&I efforts and to build a D&I strategy that directly supports the Company’s diversity and inclusion goals. To further the Company’s strategy, Apache conducted focus group sessions to gain insight into its employees’ experiences and to better understand its D&I strengths and opportunities. With this feedback in mind, Apache evaluated its recruiting, talent management, and learning efforts to identify and implement changes that would allow for increased employee opportunities, belonging, and workplace diversity.

To showcase a visible commitment, Apache launched a Diversity & Inclusion employee site that provides D&I and allyship trainings and information on how to join and initiate Employee Resource Groups (ERG). Apache currently has four ERGs: the Apache Women’s Network (AWN), Apache Young Professionals’ Network (AYPN), Apache D&I Council, and the newly formed Apache Black Professionals Network (ABPN). These groups encourage cultural awareness, professional development, community outreach, and networking. The Company looks forward to expanding its ERGs to help build employee connections and belonging, support Apache’s community outreach programs, and foster career development. Over the years to come, Apache will continue to actively support employees in forming additional demographic-based groups (e.g., ethnicity, nationality, age, sexual orientation, etc.), as well as interest-based groups (e.g., support, sports, hobbies, etc.).

Apache embraces the idea of continuous improvement in all that it does, and its D&I journey is no different. The Company is committed to continually improving and making changes throughout the organization to foster a more inclusive and diverse workforce.

Total Rewards

Apache’s total rewards are designed to attract, retain, and reward top talent. As part of its compensation philosophy, Apache offers and maintains a robust total compensation package that includes a competitive base salary, industry-leading benefits, and performance-driven incentives. The Company believes that a compensation program with both short-term and long-term incentives provides fair and competitive compensation and aligns employee and stockholder interests. Apache’s incentive compensation programs reward Company and individual performance by incorporating metrics related to Apache’s operations, financial, ESG, and workforce safety initiatives.

In addition to cash and equity compensation, the Company also promotes employee benefits that cultivate a family-friendly work environment and focus on its employees’ overall wellness. Apache’s robust benefits platform ranks among the best in the Company’s industry peer group and includes comprehensive healthcare, retirement benefits, as well as locally relevant well-being benefits.

Recent enhancements in Apache’s benefit offerings for employees include the following:

•The U.S. family leave policies include paid time off for all new parents, including adoptive and surrogate parents, and leave for employees providing elder care.

•The availability of mental health benefits to all U.S.-based employees and eligible family members, including 16 free sessions with a mental health therapist or coach each year.

•A global wellness platform, which encourages and promotes physical, financial, social, and emotional well-being.

OFFICES

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. As of year-end 2020, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache leases its primary office space. The current lease on our 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 11—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 our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that the Company’s 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 APACHE

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 Gulf of Mexico operations and offshore operations in the North Sea and Suriname, 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 Apache 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.

Additionally, Apache is an active member of Wild Well Control’s WellCONTAINED Subsea Containment System for Suriname operations. This membership includes contingency planning, and response, to an uncontrolled subsea well event. Apache utilizes a detailed Source Control Emergency Response Plan (SCERP) for offshore Suriname planning. The SCERP has been designed to ensure that the goals of Apache’s source control emergency preparedness efforts will be met in the unlikely event of an actual response to an uncontrolled well event. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control’s containment system capping stacks.

Competitive Conditions

The oil and gas business 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 natural gas liquids. Our 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 our competitors may possess financial or other resources substantially larger than we possess or have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for leases or drilling rights.

However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across three geographic areas, our balanced production mix between oil and gas, our management and incentive systems, and our experienced personnel give us a strong competitive position relative to many of our competitors who do not possess similar geographic and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which we have producing operations to which we can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. It also reduces the risk that we 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, we are subject to numerous 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, 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, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our 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 we are unable to separate expenses related to environmental matters; however, we do 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 our capital expenditures, earnings, or competitive position.


ITEM 1A.			RISK FACTORS

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

RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS (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 report, efforts to contain COVID-19 have not been successful in many regions, vaccination programs have encountered delays, and the global pandemic remains ongoing. A continued prolonged period of such reduced demand, the failure to timely distribute or the ineffectiveness of 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 implemented 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, 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 or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines 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 report.

Crude oil, natural gas, and NGL price volatility could adversely affect our operating results and the price of our common stock.

Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our 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 2020 ranged from a high of $63.27 per barrel to a low of -$36.98 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2020 ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond our control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:

•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;

•domestic and foreign governmental regulations and taxes; and

•the overall economic environment.

Our results of operations, as well as the carrying value of our oil and gas properties, are substantially dependent upon the prices of oil, natural gas, and NGLs. Despite slight increases in oil and natural gas prices in 2020, prices have remained significantly lower than levels seen in recent years, which has adversely affected our revenues, operating income, cash flow, and proved reserves. Continued low prices could have a material adverse impact on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs may further adversely impact our business as follows:

•weakening our financial condition and reducing our liquidity;

•limiting our ability to fund planned capital expenditures and operations;

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

•causing us to delay or postpone some of our capital projects;

•reducing our revenues, operating income, and cash flows;

•limiting our access to sources of capital, such as equity and long-term debt;

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

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

Our 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 our 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 our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows. Additionally, if we are unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, our cash flows could be adversely affected.

We may not realize an adequate return on wells that we drill.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us 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, this failure could have an adverse effect on our 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.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

•our production falls short of the hedged volumes;

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

•the counterparties to our 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

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

Our 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, and cratering;

•pipeline or other facility ruptures and spills;

•fires;

•formations with abnormal pressures;

•equipment malfunctions;

•hurricanes, storms, and/or cyclones, which could affect our 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

•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 we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where our equipment and services are used, or ground water contamination from hydraulic fracturing chemical additives 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 chemical additives could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, our cash flows and, in turn, our results of operations could be materially and adversely affected.

Weather and climate may have a significant adverse impact on our revenues and production.

Demand for oil and gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico, or storms in the North Sea, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our 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.

Our insurance policies do not cover all of the risks we face, 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. Our international operations are also subject to political risk. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

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

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. We depend 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 our employees and third-party partners, and conduct many of our activities. Unauthorized access to our 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 United States and abroad, which are necessary to transport and market our production. A cyberattack directed at oil and gas distribution systems 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 our customers, suppliers, or others with whom we do business could have a material adverse effect on our business, cause us to incur a material financial loss, subject us to possible legal claims and liability, and/or damage our reputation.

While certain of our insurance policies may allow for coverage of associated damages resulting from such events, if we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our 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 we have experienced cyberattacks in the past, we have not suffered any material losses as a result of such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against us or others in our 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 our 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.

We are involved in several large development projects, and the completion of these projects may be delayed beyond our anticipated completion dates. Our 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 our large development projects and our ability to participate in large-scale development projects in the future. In addition, our estimates of future development costs are based on our current expectations of prices and other costs of equipment and personnel we will need to implement such projects. Our actual future development costs may be significantly higher than we currently estimate. If costs become too high, our development projects may become uneconomic to us, and we 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 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 we add reserves through exploration and development activities, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.

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

Although we perform a review of properties that we acquire that we believe 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, we will focus our 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 us 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, we often assume 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 our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our 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. Our 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 our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:

•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 our reserves likely will vary, possibly materially, from estimates.

Additionally, because some of our 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 our 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 our 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 our 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 our leases expire, we will lose our right to develop the related properties. Our 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 us.

We are 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 us to credit risk in the event of default of our counterparty. Deterioration in the credit or financial markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We may also have exposure to financial institutions in the form of derivative transactions in connection with any hedges. We also have exposure to insurance companies in the form of claims under our policies. In addition, if any lender under our credit facilities is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facilities.

We are 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 decline 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. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

The distressed financial conditions of our purchasers and partners could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or to reimburse us 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. We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. As a result of current economic conditions and the severe decline in commodity prices, some of our customers and non-operating partners may experience severe financial problems that may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers or non-operating partners will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers or non-operating partners or some other similar proceeding or liquidity constraint might make it unlikely that we 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.

Our liabilities could be adversely affected in the event one or more of our transaction counterparties become the subject of a bankruptcy case.

From time to time we have 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, and similar arrangements. One of the most significant of these liabilities involves the decommissioning of wells and facilities previously owned by us. 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 were to become 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 we collectively refer to as Insolvency Laws), the counterparty may not perform its obligations under the agreements related to these transactions. In that case, our 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 we have collateral from the counterparty for the performance of the obligations. Resolution of our claim for damages in such a proceeding may be delayed, and we 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 our agreements requiring purchasers of our 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, we would expect the relevant governmental authorities to require us to perform and hold us responsible for such liabilities and obligations. In such event, we 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 our cash flows, operations, or financial condition.

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

We conduct many of our exploration and production (E&P) operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are 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 ours, and therefore, decisions may be made that we do not believe are in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. In either case, the value of our investment may be adversely affected.

We own an approximate 79 percent interest in Altus, which holds substantially all of our former gathering, processing and transmission assets in Alpine High. Altus may be subject to different risks than those described in this Form 10-K.

We own an approximate 79 percent interest in Altus, which holds substantially all of our 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 our production from our 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.

RISKS RELATED TO CAPITAL MARKETS

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include 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 our ability to access debt markets in the future and increase the cost of future debt. During 2020, our credit rating was downgraded by Moody’s to Ba1/Negative and by Standard and Poor’s to BB+/Negative. These and other past ratings downgrades have required, and any future downgrades may require, us to post letters of credit or other forms of collateral for certain obligations.

Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.

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

Our 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 Apache 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 our floating rate indebtedness and financing costs.

Pursuant to the terms of our revolving credit facility (1) we may elect to use 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 United Kingdom’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 on the current basis may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future 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 United States, 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 our floating rate indebtedness and financing costs under our revolving credit facility.

Our ability to declare and pay dividends is subject to limitations.

The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends.

Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including our common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is the amount by which the fair value of our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid

from our net profits for the then-current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.

RISKS RELATED TO FINANCIAL RESULTS

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

Current global market conditions and uncertainty, including the economic instability in Europe and certain emerging markets, are likely to have significant long-term effects on our 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 our oil and gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.

We face strong industry competition that may have a significant negative impact on our results of operations.

Strong competition exists in all sectors of the oil and gas E&P industry. We compete 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 our competitors have financial and other resources substantially larger than we possess and have established strategic, long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our 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. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on our 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 10—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.

RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS

We may incur significant costs related to environmental matters.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local, and foreign country 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. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

Our United States operations are subject to governmental risks.

Our United States 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. We are working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, we are 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 our United States operations, and increased liability for companies operating in this sector may adversely impact our results of operations.

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

Certain countries where we operate, including the United Kingdom, either tax or assess some form of greenhouse gas (GHG) related fees on our operations. Exposure has not been material to date, although a change in existing regulations could adversely affect our cash flows and results of operations. Additionally, there has been discussion in other countries where we operate, including the United States, regarding legislation or regulation of GHG. Any such legislation or regulation, if enacted, could either tax or assess some form of GHG-related fees on our operations and could lead to increased operating expenses or cause us to make significant capital investments for infrastructure modifications.

In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact our assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines 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, and increased risk of litigation. 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 we require to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

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

On December 22, 2017, the Tax Cuts and Jobs Act (the TCJA) was signed into law. In addition to reducing the U.S. corporate income tax rate from 35 percent to 21 percent effective January 1, 2018, certain provisions in the TCJA move the U.S. away from a worldwide tax system and closer to a territorial system for earnings of foreign corporations, establishing a participation exemption system for taxation of foreign income. The new law includes a transition rule to effect this participation exemption regime. The TCJA also includes provisions which could impact or limit the Company’s ability to deduct interest expense or utilize net operating losses.

The U.S. federal and state income tax laws affecting oil and gas exploration, development, and extraction may be further 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 exploration and production 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. We are unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect our business, financial condition, and results of operations.

Proposed federal, state, or local regulation regarding hydraulic fracturing could increase our 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. We routinely use 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.

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 we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.

RISKS RELATED TO INTERNATIONAL OPERATIONS

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

Our operations outside the United States are based primarily in Egypt and the United Kingdom. On a barrel equivalent basis, approximately 42 percent of our 2020 production was outside the United States, and approximately 33 percent of our estimated proved oil and gas reserves as of December 31, 2020, were located outside the United States. As a result, a significant portion of our 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;

•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 United States affecting foreign trade, including trade sanctions;

•the 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 we currently operate;

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

•difficulties in enforcing our 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 us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Certain regions of the world in which we operate 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 ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability.

The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which we operate, may have on the oil and gas industry in general and on our 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. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on our 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 our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC, or threats or acts of terrorism could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 20 percent of our 2020 production and accounted for 15 percent of our year-end estimated proved reserves and 24 percent of our estimated discounted future net cash flows.

Our operations are sensitive to currency rate fluctuations.

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. Our 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 our results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.

RISKS RELATED TO THE PLANNED HOLDING COMPANY REORGANIZATION

If the Holding Company Reorganization is implemented, APA Corporation, as the parent holding company of Apache, will be dependent on the operations and funds of its subsidiaries, including Apache.

If the Holding Company Reorganization is implemented, APA Corporation will become the successor issuer to, and parent holding company of, Apache. APA Corporation will have no business operations of its own. APA Corporation’s only significant assets will be the outstanding equity interests of its subsidiaries, including Apache. As a result, APA Corporation will rely on cash flows from Apache to pay dividends with respect to its common stock and to meet its financial obligations, including to service any debt obligations that APA Corporation may incur from time to time. Legal and contractual restrictions in agreements governing future indebtedness of Apache, as well as Apache’s financial condition and future operating

requirements, may limit Apache’s ability to distribute cash to APA Corporation. If Apache is limited in its ability to distribute cash to APA Corporation, or if Apache’s earnings or other available assets of are not sufficient to pay distributions or make loans to APA Corporation in the amounts or at the times necessary for APA Corporation to pay dividends with respect to its common stock and/or to meet its financial obligations, then APA Corporation’s business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.

If the Holding Company Reorganization is implemented, APA Corporation may not obtain the anticipated benefits of the reorganization into a holding company structure.

If the Holding Company Reorganization is implemented, we believe that our new operating structure will allow us to focus on running our diverse businesses independently with the goal of maximizing each of the business’ potential. However, the anticipated benefits of the planned Holding Company Reorganization may not be obtained if circumstances prevent us from taking advantage of the strategic and business opportunities that we expect it may afford us. As a result, we may incur the costs of a holding company structure without realizing the anticipated benefits, which could adversely affect our business, financial condition, cash flows, and results of operations.

Management is dedicating significant effort to the new operating structure. These efforts may divert management’s focus and resources from the Company’s operations, strategic initiatives, or development opportunities, which could adversely affect our prospects, business, financial condition, cash flows, and results of operations.

GENERAL RISK FACTORS

Certain anti-takeover provisions in our charter and Delaware law could delay or prevent a hostile takeover.

Our charter authorizes our board of directors to issue preferred stock in one or more series and to determine the voting rights and dividend rights, dividend rates, liquidation preferences, conversion rights, redemption rights, including sinking fund provisions and redemption prices, and other terms and rights of each series of preferred stock. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15 percent or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our shareholders.


ITEM 1B.			UNRESOLVED STAFF COMMENTS

As of December 31, 2020, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.


ITEM 3.			LEGAL PROCEEDINGS

The information set forth under “Legal Matters” and “Environmental Matters” in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.


ITEM 4.			MINE SAFETY DISCLOSURES

None.

PART II


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

Apache’s common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol “APA.” The closing price of our common stock, as reported by the Nasdaq for January 29, 2021 (last trading day of the month), was $14.28 per share. As of January 29, 2021, there were 377,860,971 shares of our common stock outstanding held by approximately 3,500 stockholders of record and 166,000 beneficial owners.

We have paid cash dividends on our common stock for 56 consecutive years through December 31, 2020. In the first quarter of 2020, Apache’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements, and other relevant factors.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2021 annual meeting of stockholders, which is incorporated herein by reference.

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (S&P 500 Index) and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2015, through December 31, 2020. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Apache Corporation, the S&P 500 Index,

and the Dow Jones U.S. Exploration & Production Index

* $100 invested on 12/31/15 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31.


	2015		2016		2017		2018		2019		2020
Apache Corporation	$	100.00	$	145.64	$	98.84	$	62.88	$	63.54	$	35.78
S&P 500 Index	100.00		111.96		136.40		130.42		171.49		203.04
Dow Jones U.S. Exploration & Production Index	100.00		124.48		126.10		103.69		115.51		76.64


ITEM 6.			SELECTED FINANCIAL DATA

Omitted.


ITEM 7.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 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 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 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 the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (filed with the SEC on February 28, 2020).

Overview

Apache’s mission is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of its stakeholders. Apache is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.

The global economy and the energy industry have been deeply impacted by the effects of the COVID-19 pandemic and related third-party actions. Uncertainty in the oil markets and the negative demand implications from the COVID-19 pandemic continue to impact oil supply and demand. As with previous changes in a volatile price environment, Apache has continued to respond quickly and decisively, taking the following actions:

•Decreasing the Company’s dividend by 90 percent beginning in the first quarter of 2020, preserving approximately $340 million of cash flow on an annualized basis and strengthening liquidity.

The Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate excess cash flow that can be directed on a priority basis to debt reduction. The Company closely monitors hydrocarbon pricing fundamentals and will reallocate capital as part of its ongoing planning process. For additional detail on the Company’s forward capital investment outlook, refer to “Capital and Operational Outlook” below.

During 2020, Apache reported a net loss attributable to common stock of $4.9 billion, or $12.86 per share, compared to a net loss of $3.6 billion, or $9.43 per share, in 2019. The results for both periods were driven by asset impairments. In 2020, the Company recorded impairments totaling $4.5 billion in connection with fair value assessments stemming from the global crude oil price collapse on lower demand and economic activity resulting from the impacts of COVID-19 and related third-party actions. The Company recorded asset impairments during 2019 of $2.9 billion, primarily related to a material reduction in planned investment at Apache’s Alpine High development that triggered fair value assessments of the Company’s upstream Alpine High proved properties and Altus’ associated midstream assets.

Apache’s capital spending for the year aligned with its $1.4 billion of cash from operating activities generated in 2020, which was $1.5 billion or 52 percent lower than the prior year. Apache’s lower operating cash flows for 2020 were driven by lower crude oil prices and associated revenues. The reduced capital investment was the result of proactive measures taken by the Company to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows. Apache ended the year with a slightly higher cash balance of $262 million and comparable debt levels to the prior year-end, while actively managing its debt positions to reduce near-term debt maturities.

Operational Highlights

Key operational highlights for the year include:

United States

•Equivalent production from the Company’s U.S. assets, which accounted for 58 percent of total production during 2020, decreased nine percent from 2019 to 2020 as a result of reduced activity in response to commodity price weakness.

•The Company began 2020 with seven operated drilling rigs and three operated completion crews in the Permian Basin, which were both quickly and safely reduced to zero by May 2020 in response to commodity price weakness.

•In response to completion cost reductions when compared to the first quarter of 2020, the Company reinstated two operated completion crews in the Permian Basin during the fourth quarter of 2020 to begin completing its backlog of drilled but uncompleted well inventory.

International

•Egypt gross equivalent production decreased 13 percent and net production decreased 9 percent from 2019 primarily a result of natural decline given reduced drilling activity during 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. As a result, the Egypt asset achieved a new record within the Matruh Basin with the Herunefer E-2 well, which encountered 555 feet of net pay.

•The North Sea maintained two drilling rigs during 2020 with notable discoveries at the Storr and Garten fields contributing to the two percent increase in production from 2019 to 2020. In addition, during the fourth quarter of 2020, the Company’s Losgann well confirmed a Tertiary oil discovery, offsetting other operator Norwegian discoveries in the area. In combination with two previous undeveloped Apache discoveries in the Tertiary, Losgann will add to a comprehensive development opportunity.

•In April 2020, Apache announced a significant oil discovery at the Sapakara West-1 well drilled offshore Suriname on Block 58. Sapakara West-1 was drilled to a depth of approximately 6,300 meters (approximately 20,700 feet) and successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. This follows the January 2020 announcement of a discovery at the Maka Central-1 well. During 2020, the Company submitted a plan of appraisal for both of these discoveries. Apache holds a 50 percent working interest in Block 58.

•In July 2020, Apache announced a major oil discovery at the Kwaskwasi-1 well drilled offshore Suriname on Block 58. Kwaskwasi-1 was drilled to a depth of approximately 6,645 meters (approximately 21,800 feet) and successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. Fluid samples and test results indicate at least 278 meters (approximately 912 feet) of net oil and oil/gas condensate pay in two intervals. This was the third consecutive oil discovery offshore Suriname.

•In late 2020, the Company commenced drilling a fourth exploration well in the block at the Keskesi prospect. In January 2021, Apache and Total S.A announced a discovery that confirmed oil in the eastern portion of the block. The Keskesi East-1 well is continuing to drill to deeper targets. Apache is transferring operatorship of Block 58 to its partner, Total S.A, which will conduct all exploration and appraisal activities subsequent to completion of drilling operations at Keskesi.

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.

Acquisition and Divestiture Activity

Over Apache’s history, the Company has repeatedly demonstrated its 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, Apache has completed a series of divestitures designed to monetize nonstrategic assets and enhance Apache’s portfolio in order to allocate resources to more impactful exploration and development opportunities. These divestitures include:

•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.

•Suriname Joint Venture Agreement In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. each hold a 50 percent working interest in Block 58. Apache operated the drilling of the first four wells and subsequently transferred operatorship of Block 58 to Total S.A. In connection with the agreement, Apache received $100 million 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.

Apache will also receive various other forms of consideration, including $5.0 billion of cash carry on Apache’s first $7.5 billion of appraisal and development capital, 25 percent cash carry on all of Apache’s appraisal and development capital beyond the first $7.5 billion, a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.

•Midcontinent/Gulf Coast Divestiture In the second quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the Woodford-SCOOP and STACK plays for aggregate cash proceeds of approximately $223 million. In the third quarter of 2019, Apache completed the sale of non-core, gas-weighted 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.

•U.S. Leasehold Divestitures & Other During 2019, the Company also completed the sale of certain other non-core producing assets, gathering, processing, and transmission (GPT) assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million.

For detailed information regarding Apache’s acquisitions and divestitures, refer to Note 2—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.

Results of Operations

Oil and Gas Production Revenues

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


	For the Year Ended December 31,
	2020				2019				2018
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Oil Revenues:
United States	$	1,209	39	%	$	2,098	40	%	$	2,271	39	%
Egypt(1)	1,102		35	%	1,969		38	%	2,396		41	%
North Sea	795		26	%	1,163		22	%	1,179		20	%
Total(1)	$	3,106	100	%	$	5,230	100	%	$	5,846	100	%

Natural Gas Revenues:
United States	$	251	42	%	$	293	43	%	$	458	50	%
Egypt(1)	280		47	%	295		44	%	339		37	%
North Sea	67		11	%	90		13	%	122		13	%
Total(1)	$	598	100	%	$	678	100	%	$	919	100	%

NGL Revenues:
United States	$	304	91	%	$	372	91	%	$	550	94	%
Egypt(1)	8		3	%	12		3	%	13		2	%
North Sea	21		6	%	23		6	%	20		4	%
Total(1)	$	333	100	%	$	407	100	%	$	583	100	%

Oil and Gas Revenues:
United States	$	1,764	44	%	$	2,763	44	%	$	3,279	45	%
Egypt(1)	1,390		34	%	2,276		36	%	2,748		37	%
North Sea	883		22	%	1,276		20	%	1,321		18	%
Total(1)	$	4,037	100	%	$	6,315	100	%	$	7,348	100	%

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

Production

The following table presents production volumes by country:


	For the Year Ended December 31,
	2020	Increase (Decrease)	2019	Increase (Decrease)	2018
Oil Volumes – b/d:
United States	88,249	(16)%	105,051	—	104,800
Egypt(1)(2)	75,384	(11)%	84,617	(10)%	93,656
North Sea	50,386	1%	49,746	6%	46,953
Total	214,019	(11)%	239,414	(2)%	245,409

Natural Gas Volumes – Mcf/d:
United States	561,731	(12)%	639,580	8%	593,254
Egypt(1)(2)	274,175	(4)%	285,972	(12)%	326,811
North Sea	57,464	5%	54,642	20%	45,466
Total	893,370	(9)%	980,194	2%	965,531

NGL Volumes – b/d:
United States	74,136	8%	68,381	19%	57,451
Egypt(1)(2)	754	(19)%	931	1%	923
North Sea	1,936	11%	1,739	46%	1,189
Total	76,826	8%	71,051	19%	59,563

BOE per day:(3)
United States	256,007	(9)%	280,029	7%	261,126
Egypt(1)(2)	121,834	(9)%	133,209	(11)%	149,048
North Sea(4)	61,899	2%	60,592	9%	55,719
Total	439,740	(7)%	473,830	2%	465,893

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


	2020	2019	2018
Oil (b/d)	164,104	193,886	206,378
Natural Gas (Mcf/d)	641,069	708,682	769,468
NGL (b/d)	1,429	1,722	1,502

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


	2020	2019	2018
Oil (b/d)	25,206	28,220	31,240
Natural Gas (Mcf/d)	91,540	95,539	109,169
NGL (b/d)	251	310	308

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

(4)Average sales volumes from the North Sea were 62,157 boe/d, 59,797 boe/d, and 55,568 boe/d for 2020, 2019, and 2018, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

Pricing

The following table presents pricing information by country:


	For the Year Ended December 31,
	2020		Increase (Decrease)	2019		Increase (Decrease)	2018
Average Oil Price - Per barrel:
United States	$	37.42	(32)%	$	54.71	(8)%	$	59.36
Egypt	39.95		(37)%	63.76		(9)%	70.09
North Sea	42.88		(34)%	65.10		(6)%	69.02
Total	39.60		(34)%	60.05		(8)%	65.30

Average Natural Gas Price - Per Mcf:
United States	$	1.22	(3)%	$	1.26	(41)%	$	2.12
Egypt	2.79		(1)%	2.83		—	2.84
North Sea	3.19		(29)%	4.48		(39)%	7.33
Total	1.83		(4)%	1.90		(27)%	2.61

Average NGL Price - Per barrel:
United States	$	11.21	(25)%	$	14.95	(43)%	$	26.28
Egypt	27.83		(18)%	33.87		(14)%	39.17
North Sea	29.73		(19)%	36.83		(20)%	45.84
Total	11.84		(25)%	15.74		(41)%	26.87

Crude Oil Prices A substantial portion of our 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 2020 were down 34 percent compared to 2019, a direct result of the decreasing benchmark oil prices over the past year resulting from the COVID-19 pandemic and related third-party actions. Crude oil prices realized in 2020 averaged $39.60 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. Apache’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 United States, 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 $1.22 per Mcf in 2020, down from $1.26 per Mcf in 2019.

•In Egypt, the Company’s natural gas is sold to Egyptian General Petroleum Corporation (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 $2.79 per Mcf in 2020, a 1 percent decrease from 2019.

•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 $3.19 per Mcf in 2020, a 29 percent decrease from an average of $4.48 per Mcf in 2019.

NGL Prices Apache’s U.S. NGL production, which accounts for 96 percent of the Company’s total 2020 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 2020 totaled $3.1 billion, a $2.1 billion decrease from the 2019 total of $5.2 billion. A 34 percent decrease in average realized prices reduced 2020 revenues by $1.8 billion compared to 2019, while 11 percent lower average daily production decreased revenues by $343 million. Average daily production in 2020 was 214 Mb/d, with prices averaging $39.60 per barrel. Crude oil sales accounted for 77 percent of the Company’s 2020 oil and gas production revenues and 49 percent of its worldwide production.

The Company’s worldwide crude oil production decreased 25 Mb/d compared to 2019, primarily driven by natural decline in the U.S. and Egypt, a result of reduced activity in response to commodity price weakness. Production decreases for 2020 were partially offset by the Storr and Garten exploration discoveries in the North Sea coming on-line in late 2019 and early 2020, respectively.

Natural Gas Revenues

Natural gas revenues for 2020 totaled $598 million, an $80 million decrease from the 2019 total of $678 million. A 4 percent decrease in average realized prices reduced 2020 revenues by $24 million compared to 2019, while 9 percent lower average daily production decreased revenues by $56 million. Average daily production in 2020 was 893 MMcf/d, with prices averaging $1.83 per Mcf. Natural gas sales accounted for 15 percent of the Company’s 2020 oil and gas production revenues and 34 percent of its worldwide production.

The Company’s worldwide natural gas production decreased 87 MMcf/d compared to 2019, primarily a result of the sale of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets in the U.S. in 2019 and natural decline in the U.S. and Egypt resulting from reduced activity levels.

NGL Revenues

NGL revenues for 2020 totaled $333 million, a $74 million decrease from the 2019 total of $407 million. A 25 percent decrease in average realized prices reduced 2020 revenues by $101 million compared to 2019, while 8 percent higher average daily production increased revenues by $27 million. Average daily production in 2020 was 77 Mb/d, with prices averaging $11.84 per barrel. NGL sales accounted for 8 percent of Apache’s 2020 oil and gas production revenues and 17 percent of its worldwide production.

The Company’s worldwide NGL production increased 6 Mb/d compared to 2019, primarily a result of the Alpine High development in recent years.

Altus Midstream Revenues

Apache beneficially owns approximately 79 percent of Altus’ outstanding voting common stock. Altus owns and operates a midstream energy asset network in the Permian Basin of West Texas primarily to service Apache’s production from its Alpine High resource play, which commenced production in May 2017.

Altus Midstream generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2020 and 2019, Altus Midstream’s services revenues generated through its fee-based contractual arrangements with Apache totaled $145 million and $136 million, respectively. These affiliated revenues are eliminated upon consolidation. The increase compared to the prior year was primarily driven by higher throughput of rich natural gas volumes at Alpine High due to increased capacity as a result of three cryogenic processing trains coming on line starting in the second quarter of 2019, partially offset by lower throughput of lean natural gas volumes.

Purchased Oil and Gas Sales

Purchased oil and gas sales increased $222 million for the year ended December 31, 2020 from $176 million to $398 million. Purchased oil and gas sales were primarily offset by associated purchase costs of $357 million and $142 million for the years ended December 31, 2020 and 2019, respectively.

Operating Expenses

The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2020, 2019, and 2018. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Lease operating expenses	$	1,127	$	1,447	$	1,439
Gathering, processing, and transmission	274		306		348
Purchased oil and gas costs	357		142		340
Taxes other than income	123		207		215
Exploration	274		805		503
General and administrative	290		406		431
Transaction, reorganization, and separation	54		50		28
Depreciation, depletion, and amortization:
Oil and gas property and equipment	1,643		2,512		2,265
Gathering, processing, and transmission assets	76		105		83
Other assets	53		63		57
Asset retirement obligation accretion	109		107		108
Impairments	4,501		2,949		511
Financing costs, net	267		462		478

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 49 percent of the Company’s total 2020 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2020, LOE decreased $320 million, or 22 percent, compared to 2019. On a per-boe basis, LOE decreased $1.38, or 16 percent, compared to 2019, from $8.38 per boe to $7.00 per boe, driven by reduced activity, labor costs, and fuel costs associated with lower commodity prices, the Company’s organizational redesign, and other cost cutting efforts. In addition, absolute dollar costs are lower in the current year as a result of the divestitures of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets in the U.S. in the third quarter of 2019.

Gathering, Processing, and Transmission (GPT)

GPT expenses include amounts paid to third-party carriers and to Altus Midstream for gathering and transmission services for Apache’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,
	2020		2019		2018
	(In millions)
Third-party processing and transmission costs	$	236	$	250	$	294
Midstream service affiliate costs	143		134		77
Upstream processing and transmission costs	379		384		371
Midstream operating expenses	38		56		54
Intersegment eliminations	(143)		(134)		(77)
Total Gathering, processing, and transmission	$	274	$	306	$	348

GPT costs decreased $32 million compared to 2019. Third-party processing and transmission costs decreased $14 million, primarily driven by a decrease in contracted pricing and the Company’s sale of non-core assets in Oklahoma and Texas. Midstream service affiliate costs increased $9 million compared to 2019, primarily driven by higher throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, incurred primarily by Altus, decreased $18 million compared to 2019, primarily driven by increased operational efficiency as a result of transitioning from mechanical refrigeration units to Altus’ centralized Diamond cryogenic complex starting in the second quarter of 2019. The transition resulted in decreases in employee-related costs, contract labor, supplies expenses, and equipment rentals.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $215 million compared to 2019, and were more than offset by associated sales totaling $398 million for the year ended 2020.

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 decreased $84 million compared to 2019, primarily from lower severance taxes driven by lower commodity prices and the divestiture of the Company’s non-core assets in Oklahoma and Texas.

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,
	2020		2019		2018
	(In millions)
Unproved leasehold impairments	$	101	$	619	$	214
Dry hole expenses	110		57		137
Geological and geophysical expenses	20		59		55
Exploration overhead and other	43		70		97
Total Exploration	$	274	$	805	$	503

Exploration expenses decreased $531 million compared to 2019. Unproved leasehold impairments decreased $518 million, driven by higher leasehold impairments in 2019 associated with the Company’s decision to reallocate capital away from planned investment in the Alpine High play. Dry hole expense increased $53 million compared to 2019, primarily related to exploration wells in the U.S., Egypt, and the North Sea. Geological and geophysical expenses decreased $39 million and exploration overhead and other expenses decreased $27 million. The 2019 period reflects large-scale seismic surveys in Egypt and higher delay rentals in the U.S.

General and Administrative (G&A) Expenses

G&A expenses decreased $116 million compared to 2019, primarily related to cost-cutting measures associated with the Company’s organizational redesign efforts, as well as lower cash-based stock compensation expense resulting from a decrease in the Company’s stock price and a reduced payout of performance awards.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs increased $4 million compared to 2019, driven by costs associated with the Company’s reorganization efforts initiated in the second half of 2019.

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 Apache’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, and as a result of the reorganization, Apache has achieved an estimated cost savings of more than $400 million annually.

Depreciation, Depletion and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2020, decreased $869 million compared to 2019. The Company’s oil and gas property DD&A rate decreased $4.35 per boe in 2020 compared to 2019, from $14.55 per boe to $10.20 per boe. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded in the first quarter of 2020 and in the fourth quarter of 2019. DD&A expense on the Company’s GPT depreciation decreased $29 million compared to 2019, driven by impairment charges recorded against the carrying value of Altus’ GPT facilities in the fourth quarter of 2019.

Impairments

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.

During 2019, the Company recorded asset impairments totaling $2.9 billion in connection with fair value assessments, including $1.5 billion for oil and gas proved properties in the U.S. primarily in Alpine High, $1.3 billion impairment of GPT facilities primarily in the Altus Midstream reporting segment, $149 million on divested unproved properties and leasehold acreage in the western Anadarko Basin in Oklahoma and Texas, and $21 million of inventory and other miscellaneous assets, including office leasehold impairments from Apache’s announcement to close its San Antonio regional office. The impairments for Alpine High and Altus Midstream were associated with the Company’s fourth quarter 2019 capital plan allocation decision to materially reduce planned investment in the Alpine High play.

The following table presents a summary of asset impairments recorded for 2020, 2019, and 2018:


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Oil and gas proved property	$	4,319	$	1,484	$	328
GPT facilities	68		1,295		56
Equity method investment	—		—		113
Divested unproved properties and leasehold	—		149		10
Goodwill	87		—		—
Inventory and other	27		21		4
Total Impairments	$	4,501	$	2,949	$	511

Financing Costs, Net

Financing costs incurred during the period comprised the following:


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Interest expense	$	438	$	430	$	441
Amortization of debt issuance costs	8		7		9
Capitalized interest	(12)		(37)		(44)
Loss (gain) on extinguishment of debt	(160)		75		94
Interest income	(7)		(13)		(22)
Total Financing costs, net	$	267	$	462	$	478

Net financing costs decreased $195 million compared to 2019, primarily the result of a $160 million gain on extinguishment of debt during 2020 compared to a $75 million loss on extinguishment of debt during 2019. In addition, capitalized interest decreased in the current year as a result of lower drilling activity and construction activity at Alpine High.

Provision for Income Taxes

Income tax expense decreased $610 million from $674 million during 2019 to $64 million during 2020. The Company’s year-to-date 2020 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’s year-to-date 2019 effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets.

The Company 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 10—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Apache 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.

Capital and Operational Outlook

The Company continues to prudently manage its capital program against a volatile price environment and the prolonged effects of the COVID-19 pandemic. In response to the current crises, Apache’s immediate course of action has been to actively reduce its cost structure, protect its balance sheet, and manage operations to preserve cash flow. The Company plans to maintain a conservative investment approach into 2021, having announced an upstream capital program of $1.1 billion. The program consists of approximately $900 million for development activities and approximately $200 million for exploration, predominantly in Suriname.

The 2021 capital program assumes an average WTI price of $45 per barrel and a Henry Hub natural gas price of $3.00 per Mcf. In 2020, a higher percentage of development capital was directed toward international projects that generate better returns in a lower price environment. With the improvement in oil prices, the Company is returning to a modest level of activity in the U.S. Under the capital budget for 2021, activity includes:

•continuing to advance exploratory and appraisal programs in Suriname under the terms of the Company’s joint venture with Total S.A.;

•running one rig in the Permian Basin, with the expectation to add a second rig in the middle of the year, while resuming completion activity for its previously drilled but uncompleted well inventory in response to significantly lower service costs;

•continuing to run a five rig drilling program in Egypt with the ability to quickly flex spending as conditions warrant; and

•maintaining a capital program in the North Sea relatively unchanged from the prior year with one floating rig and one platform crew.

The Company’s proactive reduction in capital spending in 2020 directly impacted global oil volumes which decreased by 17 percent from the fourth quarter of 2019 to the fourth quarter of 2020. Based on its 2021 upstream investment plan and allocation, the Company is projecting a more moderate decline of one percent for the comparable 2021 period. Forecasting into 2022 and future years, Apache’s goal is to establish a development capital investment budget that will, at a minimum, at least sustain production volumes for the longer-term.

Apache’s strategic approach and multi-year outlook prioritizes retaining cash flow to reduce outstanding debt, focusing on long-term returns over short-term growth, aggressively managing its cost structure, and advancing exploration and appraisal activities in Suriname.

The Company’s diversified global portfolio provides the ability to quickly optimize capital allocation as market conditions change. The current crisis, however, is still evolving and may become more severe and complex. As a result, the COVID-19 pandemic may still materially and adversely affect Apache’s results in a manner that is either not currently known or that the Company does not currently consider to be a significant risk to its business. For additional information about the business risks relating to the COVID-19 pandemic and related governmental actions, refer to Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K.

Separate from the Company’s upstream oil and gas activities, capital spending for Altus’ gathering and processing assets totaled $28 million in 2020, down from $327 million in 2019 when a majority of the midstream infrastructure construction was completed. Altus management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and any third-party customers. As such, remaining capital requirements for its existing infrastructure assets during 2021 and 2022 are anticipated to be minimal.

Additionally, during the years ended December 31, 2020 and 2019, Altus made cash contributions totaling $327 million and $501 million, respectively, for its equity interests in the following Equity Method Interest Pipelines:

•16 percent in the Gulf Coast Express natural gas pipeline (GCX);

•15 percent in the EPIC crude pipeline (EPIC);

•an approximate 26.7 percent in the Permian Highway natural gas pipeline (PHP); and

•33 percent in the Shin Oak NGL pipeline (Shin Oak).

Altus estimates it will incur approximately $30 million of additional capital contributions during 2021 for its equity interest associated with the commissioning and remaining construction costs in the Equity Method Interest Pipelines, primarily associated with PHP. During 2020, Altus’ primary sources of cash were borrowings under the revolving credit facility, cash generated from operations, distributions from the Equity Method Interest Pipelines, and proceeds from the sale of assets. Based on Altus’ current financial plan and related assumptions, it believes that cash from operations, a reduced capital program for its midstream infrastructure, and distributions from equity method interests will generate cash flows significantly in excess of capital expenditures that will provide sufficient cash to fund its planned dividend program during 2021.

For further information on the Equity Method Interest Pipelines, refer to Note 6 —Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Capital Resources and Liquidity

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

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. For the year ended December 31, 2020, Apache recognized negative reserve revisions of approximately 7 percent of its year-end 2019 estimated proved reserves as a result of lower prices. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2020, 2019, and 2018, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18—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.

Combined with proactive measures to adjust its capital budget, decrease its dividend, protect further downside price risk through entering into new hedge positions, and reduce its operating cost structure in the current volatile commodity price environment, Apache believes the liquidity and capital resource alternatives available to the Company will be adequate to fund its operations and provide flexibility until commodity prices and industry conditions improve. This includes supporting the Company’s capital development program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.

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

For additional information, please see Part I, Items 1 and 2—Business and Properties and Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K.

Sources and Uses of Cash

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


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	1,388	$	2,867	$	3,777
Proceeds from Apache credit facility, net	150		—		—
Proceeds from Altus credit facility, net	228		396		—
Proceeds from Altus transaction	—		—		628
Proceeds from asset divestitures	166		718		138
Fixed-rate debt borrowings	1,238		989		992
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	—		611		—

	3,170		5,581		5,535
Uses of Cash and Cash Equivalents:
Additions to oil and gas property(1)	$	1,270	$	2,594	$	3,190
Additions to Altus gathering, processing, and transmission facilities(1)	28		327		581
Leasehold and property acquisitions	4		40		133
Contributions to Altus equity method interests	327		501		—
Acquisition of Altus equity method interests	—		671		91
Payments on fixed-rate debt	1,243		1,150		1,370
Dividends paid	123		376		382
Distributions to noncontrolling interest - Egypt	91		305		345
Distributions to Altus Preferred Unit limited partners	23		—		—
Shares repurchased	—		—		305
Other	46		84		92
	3,155		6,048		6,489
Increase (decrease) in cash and cash equivalents	$	15	$	(467)	$	(954)

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

Sources of Cash and Cash Equivalents

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

Net cash provided by operating activities for the year ended December 31, 2020 totaled $1.4 billion, down $1.5 billion from the year ended December 31, 2019. The decrease primarily reflects lower commodity prices compared to the prior year.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Proceeds from Apache Credit Facility, Net As of December 31, 2020, there were $150 million of borrowings outstanding under Apache’s credit facility, which is classified as long-term debt. The Company had no borrowings under the revolver as of December 31, 2019.

Proceeds from Altus Credit Facility, Net The initial construction of Altus’ gathering and processing assets and the exercise of its Pipeline Options for its equity interests in the Equity Method Interest Pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the years ended December 31, 2020 and 2019, Altus Midstream borrowed $228 million and $396 million, respectively, under its revolving credit facility. With the initial midstream infrastructure construction complete and each of Shin Oak, GCX, PHP, and EPIC now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and planned dividend program during 2021.

Proceeds from Asset Divestitures The Company recorded proceeds from non-core asset divestitures totaling $166 million and $718 million for the years ended December 31, 2020 and 2019, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part IV set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Fixed-Rate Debt Borrowings On August 17, 2020, the Company 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 the Company’s senior revolving credit facility, and for general corporate purposes.

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 (2030 notes) and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049 (2049 notes). The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The aggregate net proceeds of $989 million from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.

Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable 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. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. For more information, refer to Note 13—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Uses of Cash and Cash Equivalents

Additions to Oil & Gas Property Exploration and development cash expenditures were $1.3 billion and $2.6 billion for the years ended December 31, 2020 and 2019, respectively. The decrease in capital investment is reflective of the Company’s reduced capital program as the Company eliminated nearly all drilling and completion activities in the U.S. by May 2020 in response to commodity price impacts stemming from the COVID-19 pandemic. A majority of the current year expenditures shifted from the Company’s Permian Basin assets to its Egypt assets over the second half of 2020. The Company operated an average of 12 drilling rigs during 2020 compared to 23 drilling rigs during 2019.

Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $28 million and $327 million during 2020 and 2019, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for 2021 and 2022 to be minimal.

Leasehold and Property Acquisitions During 2020 and 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million and $40 million, respectively.

Contributions to Altus Equity Method Interests Altus made contributions of $327 million and $501 million during 2020 and 2019, respectively, for equity interests in the Equity Method Interest Pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Acquisitions of Altus Equity Method Interests Altus made acquisitions of equity method interests totaling $671 million during the year ended December 31, 2019. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

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

During 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 $183 million of 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.

On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of notes for approximately $1.0 billion, which included principal, the net premium to par, and an early tender premium totaling $28 million, as well as accrued and unpaid interest of $14 million. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discounts, in connection with the note purchases. Additionally, on July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid.

Dividends The Company paid $123 million and $376 million cash dividends on its common stock for the years ended December 31, 2020 and 2019, respectively. In the first quarter of 2020, Apache’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.

Distributions to Noncontrolling Interests - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt. The Company made cash distributions totaling $91 million and $305 million to Sinopec during the years ended December 31, 2020 and 2019, respectively.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid cash distributions of $23 million to its limited partners holding Preferred Units for the year ended December 31, 2020. No cash distributions were made during 2019. For more information regarding the Preferred Units, refer to Note 13 —Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Liquidity

The following table presents a summary of the Company’s key financial indicators as of December 31,:


	2020		2019
	(In millions)
Cash and cash equivalents	$	262	$	247
Total debt - Apache	8,148		8,170
Total debt - Altus	624		396
Total equity (deficit)	(645)		4,465
Available committed borrowing capacity - Apache	2,944		4,000
Available committed borrowing capacity - Altus	176		404

Cash and Cash Equivalents As of December 31, 2020, the Company had $262 million in cash and cash equivalents, of which approximately $24 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of December 31, 2020, outstanding debt, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations, totaled $8.8 billion. As of December 31, 2020, current debt included $2 million of finance lease obligations. Apache intends to reduce debt outstanding under its indentures from time to time.

Available Credit Facilities In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2020. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.

As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. As of December 31, 2019, there were no borrowings or letters of credit outstanding under this facility. The £633 million in outstanding letters of credit were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced the Company’s credit rating from BBB to BB+ on March 26, 2020.

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 London Inter-bank Offered Rate (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 the Company’s senior long-term debt rating. At December 31, 2020, 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 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. At December 31, 2020, Apache’s debt-to-capital ratio as calculated under the credit facility was 32 percent. The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on their 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 United States 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 $1.7 billion as of December 31, 2020. 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, 2020 and 2019, there were $624 million and $396 million, respectively, 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 Apache 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 $350.0 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, 2020 was less than 4.00:1.00.

The terms of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Apache and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13—Redeemable Noncontrolling Interest - Altus set forth in Part IV, Item 15 of this Annual Report on Form 10-K 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 Apache or any of Apache’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, 2020.

There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to Apache or its subsidiaries or the composition of such lenders.

There is no assurance that the financial condition of banks with lending commitments to Apache or Altus Midstream LP will not deteriorate. We closely monitor the ratings of the banks in our bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Commercial Paper Program Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in Apache’s credit ratings during 2020, the Company does not expect that its commercial paper program will be cost competitive with its other financing alternatives and does not anticipate using it under such circumstances. As of December 31, 2020 and 2019, the Company had no commercial paper outstanding.

Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2020. For additional information regarding these obligations, refer to Note 9—Debt and Financing Costs and Note 11—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.


	On-Balance Sheet												Off-Balance Sheet
Obligations by Period	Debt, at Face Value		Apache Credit Facility(1)		Altus Credit Facility(1)		Interest Payments		Finance Leases(2)		Operating Leases(3)		Purchase Obligations(4)		Total(5)
	(In millions)
2021	$	—	$	—	$	—	$	415	$	3	$	120	$	236	$	774
2022	213		—		—		397		3		70		203		886
2023	123		—		624		392		3		33		203		1,378
2024	—		150		—		391		4		27		160		732
2025	500		—		—		391		4		7		159		1,061
Thereafter	7,216		—		—		4,404		29		25		600		12,274
Total	$	8,052	$	150	$	624	$	6,390	$	46	$	282	$	1,561	$	17,105

(1)Includes outstanding principal amounts at December 31, 2020. This table does not include future commitment fees, interest expense, or other fees on the Company’s credit facilities because they are floating rate instruments, and management cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

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

(3)Amounts represent future lease 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.

(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 $120 million, $111 million, and $132 million for 2020, 2019, and 2018, respectively.

(5)This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations. For additional information regarding these liabilities, please see Notes 8 —Asset Retirement Obligation and Note 12 —Retirement and Deferred Compensation Plans, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $70 million for various contingent legal liabilities. For a detailed discussion of the Company’s lease obligations, purchase obligations, environmental and legal contingencies, and other commitments, please see Note 11—Commitments and Contingencies and Note 12 —Ret irement and Deferred Com pens ation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

As further described above under “Capital and Operational Outlook,” Altus Midstream LP and/or its subsidiaries have exercised four of the five Pipeline Options to acquire equity interests in the Equity Method Interest Pipelines. The fifth Pipeline Option to acquire an equity interest in a separate intra-basin NGL pipeline was not exercised and expired on March 2, 2020. Following the exercise of each Pipeline Option, Altus Midstream LP and/or its subsidiaries may be required to fund future capital expenditures for its equity interest share in the development of the applicable pipeline. The Company estimates that Altus, based on its equity interests in each pipeline, will incur approximately $30 million of additional capital contributions for its equity interests during 2021.

With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (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.

Potential Asset Retirement Obligations

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

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

Insurance Program

Apache 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 Apache 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.

Current insurance policies covering physical damage to the Company’s assets provide up to $1 billion in coverage per occurrence. These policies also provide sudden and accidental pollution coverage. The Company’s current insurance policies covering general liabilities provide $500 million in coverage, scaled to Apache’s interest. Service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

Apache purchases multi-year political risk insurance from U.S. International Development Finance Corporation (DFC), successor to Overseas Private Investment Corporation (OPIC), and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. The Islamic Corporation for the Insurance of Investment and Export Credit (ICIEC, an agency of the Islamic Development Bank) reinsures DFC. 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.

Apache has an additional insurance policy with DFC, which, subject to policy terms and conditions, provides up to $300 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $150 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

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

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 Apache’s supplemental oil and gas disclosures. For more information regarding Apache’s supplemental oil and gas disclosures, Refer to Note 1 8 —Supplem ental Oil and Gas Disclosures (Unaudit ed ) 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 12 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.

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

Oil and Gas Exploration Costs

Apache 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.

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.

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, 2019, and 2018. 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. Apache’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 Apache’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).

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 our 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 we view and manage our 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 result of continuing negative demand implications of the COVID-19 pandemic. The Company continually monitors its market risk exposure, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets subsequent to the year ended December 31, 2019.

The Company’s average crude oil realizations decreased 34 percent to $39.60 per barrel in 2020 from $60.05 per barrel in 2019. The Company’s average natural gas price realizations decreased 4 percent to $1.83 per Mcf in 2020 from $1.90 per Mcf in 2019. The Company’s average NGL realizations decreased 25 percent to $11.84 per barrel in 2020 from $15.74 per barrel in 2019. Based on average daily production for 2020, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $78 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 $33 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 $28 million.

Apache periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. Apache does not hold or issue derivative instruments for trading purposes. As of December 31, 2020, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $11 million. The impact of a 10 percent movement in natural gas prices would be immaterial to the fair value of the commodity derivatives. These fair value changes assume volatility based on prevailing market parameters at December 31, 2020. See Note 4—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, 2020, Apache had approximately $8.1 billion net carrying value of notes and debentures outstanding, all of which was fixed-rate debt, with a weighted average interest rate of 4.98 percent. Although near-term changes in interest rates may affect the fair value of Apache’s fixed-rate debt, they do not expose the Company to the risk of earnings or cash flow loss associated with that debt. Apache is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its commercial paper program and credit facilities. As of December 31, 2020, the Company’s cash and cash equivalents totaled approximately $262 million, approximately 46 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2020, the Company had credit facility borrowings of $150 million and $624 million under its Apache and Altus credit facilities, respectively. A change in the interest rate applicable to the Company’s 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 under its commercial paper program, revolving credit facilities, and money market lines of credit.

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, and the majority of costs incurred are paid in British pounds. In Egypt, substantially all oil and gas production is sold under U.S. dollar contracts, and the majority of the 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. 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 $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 2020.

The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. Apache has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. The Company had no outstanding foreign exchange derivative contracts as of December 31, 2020.


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-65 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, 2020, 2019, and 2018, 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 our disclosure controls and procedures as of December 31, 2020, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are 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. We made no changes in internal controls over financial reporting during the quarter ending December 31, 2020, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

Management’s Annual Report on Internal Control Over Financial Reporting; Attestation Report of the Registered Public Accounting Firm

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.

The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the “Report of Independent Registered Public Accounting Firm,” included on Page F-3 through F-5 in Part IV, Item 15 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2020, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.


ITEM 9B.			OTHER INFORMATION

None.

PART III


ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Information About Our Executive Officers,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2021 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.

On January 4, 2021, the Company announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, the Company will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, the Company will be a wholly-owned subsidiary of APA, APA will be the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act, and APA will replace the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA”. If the holding company reorganization is completed prior to the date that the Proxy Statement is filed with the SEC, then the Proxy Statement will be filed by APA, as successor issuer to the Company.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 5610 of the Nasdaq, we are required to adopt a code of business conduct and ethics for our directors, officers, and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct and Ethics (Code of Conduct) and revised it in September 2020. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apachecorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within four business days and maintained for at least 12 months. Information on our 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.


ITEM 11.			EXECUTIVE COMPENSATION

The information set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Potential Payments Upon Termination or Change in Control” and “Director Compensation Table” in the Proxy Statement is incorporated herein by reference.


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

The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.


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

The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.


ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES

The information set forth under the caption “Ratification of Appointment of Independent Auditors” in the Proxy Statement is incorporated herein by reference.

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			F-2
Report of independent registered public accounting firm			F-3
Statement of consolidated operations for each of the three years in the period ended December 31, 2020			F-6
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2020			F-7
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2020			F-8
Consolidated balance sheet as of December 31, 2020 and 2019			F-9
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2020			F-10
Notes to consolidated financial statements			F-11


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


EXHIBIT NO.		DESCRIPTION
3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2	–	Certificate of Amendment of Restated Certificate of Incorporation of Registrant, dated May 14, 2015, as filed with the Secretary of State of Delaware on May 14, 2015 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed May 20, 2015, SEC File No. 001-04300).
3.3	–	Amended and Restated Bylaws of Registrant, dated October 31, 2019 (incorporated by reference to Exhibit 3.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, 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 4.1 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).


EXHIBIT NO.		DESCRIPTION
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).
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).
4.21	–	Description of Equity Securities of the Registrant (incorporated by reference to Exhibit 4.26 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
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	–	Apache Corporation 401(k) Savings Plan, as amended and restated, dated March 17, 2015, effective January 31, 2014 (incorporated by reference to Exhibit 10.15 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.3	–	Amendment to Apache Corporation 401(k) Savings Plan, dated April 17, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).
†10.4	–	Amendment to Apache Corporation 401(k) Savings Plan, dated May 16, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.5	–	Amendment to Apache Corporation 401(k) Savings Plan, effective February 3, 2016 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.6	–	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).
†10.7	–	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).
†10.8	–	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).
†10.9	–	Apache Corporation 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 16, 2016, SEC File No. 001-4300).
†10.10	–	First Amendment to the Apache Corporation 2016 Omnibus Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.11	–	Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.12	–	First Amendment to the Apache Corporation 2011 Omnibus Equity Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.15 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.13	–	Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.14	–	Apache Corporation Income Continuance Plan, as amended and restated effective as of July 29, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, SEC File No. 001-4300).
†10.15	–	Apache Corporation Deferred Delivery Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.16	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 13, 2017 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, SEC File No. 001-4300).
†10.17	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.18	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
†10.19	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.20	–	Apache Corporation Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.21	–	Retirement Agreement, dated January 19, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.22	–	Apache Corporation Executive Termination Policy, as amended and restated effective as of July 29, 2019 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, SEC File No. 001-4300).
†10.23	–	2016 Employee Release and Settlement Agreement between Registrant and Thomas E. Voytovich, effective November 30, 2015 (incorporated by reference to Exhibit 10.41 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.24	–	2018 Employee Release and Benefits Agreement between Registrant and W. Kregg Olson, effective August 1, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.25	–	Form of 2017 Performance Share Program Award Notice and Agreement, dated December 13, 2016 (incorporated by reference to Exhibit 10.45 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2016, SEC File No. 001-4300).
†10.26	–	Form of Stock Option Award Agreement, dated February 3, 2016 (incorporated by reference to Exhibit 10.61 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.27	–	Form of Stock Option Grant Agreement, dated December 13, 2016 (2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.48 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2016, SEC File No. 001-4300).
†10.28	–	Form of 2018 Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.43 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.29	–	Form of 2018 Cash-Settled Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.30	–	Form of 2018 Performance Share Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.31	–	Form of 2018 Stock Option Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.32	–	Form of 2019 Performance Share Program (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.33	–	Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.34	–	Form of 2019 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.47 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.35	–	Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.48 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.36	–	Amendment of Performance Share Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.52 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.37	–	Amendment of Restricted Stock Unit Award Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.53 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.38	–	Amendment of Stock Option Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.54 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.39	–	Form of 2020 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.55 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.40	–	Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.56 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.41	–	Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.57 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.42	–	Form of 2020 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.58 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
*†10.43	–	Form of 2021 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*†10.44	–	Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.


EXHIBIT NO.		DESCRIPTION
*†10.45	–	Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*†10.46	–	Form of 2021 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*21.1	–	Subsidiaries of Registrant.
*23.1	–	Consent of Ernst & Young LLP.
*23.2	–	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.
*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.

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 25, 2021

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 25, 2021

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer
(principal financial officer)

February 25, 2021

/s/ Rebecca A. Hoyt

Rebecca A. Hoyt

Senior Vice President, Chief Accounting Officer, and Controller
(principal accounting officer)

February 25, 2021

/s/ Annell R. Bay

Annell R. Bay

Director

February 25, 2021

/s/ Juliet S. Ellis
Juliet S. Ellis

Director

February 25, 2021

/s/ Chansoo Joung
Chansoo Joung

Director

February 25, 2021

/s/ Rene R. Joyce
Rene R. Joyce

Director

February 25, 2021

/s/ John E. Lowe

John E. Lowe

Director, Non-Executive Chairman of the Board

February 25, 2021

/s/ H. Lamar McKay

H. Lamar McKay

Director

February 25, 2021

/s/ William C. Montgomery

William C. Montgomery

Director

February 25, 2021

/s/ Amy H. Nelson

Amy H. Nelson

Director

February 25, 2021

/s/ Daniel W. Rabun

Daniel W. Rabun

Director

February 25, 2021

/s/ Peter A. Ragauss

Peter A. Ragauss

Director

February 25, 2021

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, 2020. 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, 2020.

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 25, 2021

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on Internal Control Over Financial Reporting

We have audited Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Apache Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, 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, 2020, and the related notes and our report dated February 25, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.

/s/ Ernst & Young LLP

Houston, Texas

February 25, 2021

F-2

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, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 25, 2021 expressed an unqualified opinion thereon.

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 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. 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.

F-3


						Depreciation, depletion and amortization and impairment of property and equipment
Description of the Matter						At December 31, 2020, the carrying value of the Company’s property and equipment was $8,819 million, and depreciation, depletion and amortization (DD&A) expense was $1,772 million, and impairment expense was $4,501 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. When circumstances indicate that the carrying value of property and equipment may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets. If the expected undiscounted pre-tax future cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. 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. Additionally, the expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes from estimated oil and gas reserves. 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, 2020. Auditing the Company’s DD&A and impairment 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 and impairment, 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 and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports.

F-4


						Accounting for asset retirement obligation for the North Sea segment
Description of the Matter						At December 31, 2020, the asset retirement obligation (ARO) balance totaled $1,944 million. As further described in Note 8, 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.
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.

/s/ Ernst & Young LLP

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

Houston, Texas

February 25, 2021

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS


	For the Year Ended December 31,
	2020		2019		2018
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues	$	4,037	$	6,315	$	7,348
Purchased oil and gas sales	398		176		357
Total revenues	4,435		6,491		7,705
Derivative instrument losses, net	(223)		(35)		(17)
Gain on divestitures, net	32		43		23
Other	64		54		53
	4,308		6,553		7,764
OPERATING EXPENSES:
Lease operating expenses	1,127		1,447		1,439
Gathering, processing, and transmission	274		306		348
Purchased oil and gas costs	357		142		340
Taxes other than income	123		207		215
Exploration	274		805		503
General and administrative	290		406		431
Transaction, reorganization, and separation	54		50		28
Depreciation, depletion, and amortization	1,772		2,680		2,405
Asset retirement obligation accretion	109		107		108
Impairments	4,501		2,949		511
Financing costs, net	267		462		478
	9,148		9,561		6,806
NET INCOME (LOSS) BEFORE INCOME TAXES	(4,840)		(3,008)		958
Current income tax provision	176		660		894
Deferred income tax provision (benefit)	(112)		14		(222)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(4,904)		(3,682)		286
Net income (loss) attributable to noncontrolling interest - Egypt	(121)		167		245
Net income (loss) attributable to noncontrolling interest - Altus	1		(334)		1
Net income attributable to Altus Preferred Unit limited partners	76		38		—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(4,860)	$	(3,553)	$	40





NET INCOME (LOSS) PER COMMON SHARE:


Basic	$	(12.86)	$	(9.43)	$	0.11



Diluted	$	(12.86)	$	(9.43)	$	0.11
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	378		377		382
Diluted	378		377		384

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	$	(4,904)	$	(3,682)	$	286
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	(2)		13		—
Share of equity method interests other comprehensive loss	—		(1)		—
	(2)		12		—
COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTERESTS	(4,906)		(3,670)		286
Comprehensive income (loss) attributable to noncontrolling interest - Egypt	(121)		167		245
Comprehensive income (loss) attributable to noncontrolling interest - Altus	1		(334)		1
Comprehensive income attributable to Altus Preferred Unit limited partners	76		38		—
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(4,862)	$	(3,541)	$	40

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interests	$	(4,904)	$	(3,682)	$	286
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Unrealized derivative instrument losses (gains), net	87		44		(103)
Gain on divestitures, net	(32)		(43)		(23)
Exploratory dry hole expense and unproved leasehold impairments	211		676		351
Depreciation, depletion, and amortization	1,772		2,680		2,405
Asset retirement obligation accretion	109		107		108
Impairments	4,501		2,949		511
Provision for (benefit from) deferred income taxes	(112)		14		(222)
Loss (gain) from extinguishment of debt	(160)		75		94
Other	102		50		125
Changes in operating assets and liabilities:
Receivables	149		133		150
Inventories	19		(41)		(6)
Drilling advances	(21)		(21)		(11)
Deferred charges and other	(21)		51		83
Accounts payable	(167)		(5)		77
Accrued expenses	(163)		(84)		5
Deferred credits and noncurrent liabilities	18		(36)		(53)
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,388		2,867		3,777
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,270)		(2,594)		(3,190)
Additions to Altus gathering, processing, and transmission (GPT) facilities	(28)		(327)		(581)
Leasehold and property acquisitions	(4)		(40)		(133)
Contributions to Altus equity method interests	(327)		(501)		—
Acquisition of Altus equity method interests	—		(671)		(91)
Proceeds from asset divestitures	166		718		138
Other	(3)		(31)		(87)
NET CASH USED IN INVESTING ACTIVITIES	(1,466)		(3,446)		(3,944)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	150		—		—
Proceeds from Altus credit facility	228		396		—
Fixed rate debt borrowings	1,238		989		992
Payments on fixed-rate debt	(1,243)		(1,150)		(1,370)
Proceeds from Altus transaction	—		—		628
Distributions to noncontrolling interest - Egypt	(91)		(305)		(345)
Distributions to Altus Preferred Unit limited partners	(23)		—		—
Redeemable noncontrolling interest - Altus Preferred Unit limited partners	—		611		—
Dividends paid	(123)		(376)		(382)
Treasury stock activity, net	1		2		(305)
Other	(44)		(55)		(5)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	93		112		(787)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	15		(467)		(954)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	247		714		1,668
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	262	$	247	$	714
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	419	$	394	$	402
Income taxes paid, net of refunds	$	212	$	649	$	867

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
In millions except share and per-share amounts	2020		2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ($24 and $6 related to Altus VIE)	$	262	$	247
Receivables, net of allowance of $95 and $88	908		1,062
Other current assets (Note 5) ($5 and $5 related to Altus VIE)	676		652
	1,846		1,961
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	41,217		40,540
Unproved properties and properties under development	602		666
Gathering, processing, and transmission facilities ($206 and $203 related to Altus VIE)	670		799
Other ($3 and $4 related to Altus VIE)	1,140		1,140
	43,629		43,145
Less: Accumulated depreciation, depletion, and amortization ($13 and $1 related to Altus VIE)	(34,810)		(28,987)
	8,819		14,158
OTHER ASSETS:
Equity method interests (Note 6) ($1,555 and $1,258 related to Altus VIE)	1,555		1,258
Deferred charges and other ($5 and $4 related to Altus VIE)	526		730
	$	12,746	$	18,107
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	444	$	695
Current debt (nil and $10 related to Altus VIE)	2		11
Other current liabilities (Note 7) ($4 and $21 related to Altus VIE)	862		1,149
	1,308		1,855
LONG-TERM DEBT (Note 9) ($624 and $396 related to Altus VIE)	8,770		8,555
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	215		346
Asset retirement obligation ($64 and $60 related to Altus VIE)	1,888		1,811
Other ($144 and $107 related to Altus VIE)	602		520
	2,705		2,677
COMMITMENTS AND CONTINGENCIES (Note 11)

REDEEMABLE NONCONTROLLING INTEREST - ALTUS PREFERRED UNIT LIMITED PARTNERS (Note 13)	608		555

EQUITY (DEFICIT):
Common stock, $0.625 par, 860,000,000 shares authorized, 418,429,375 and 417,026,863 shares issued, respectively	262		261
Paid-in capital	11,735		11,769
Accumulated deficit	(10,461)		(5,601)
Treasury stock, at cost, 40,946,745 and 40,964,193 shares, respectively	(3,189)		(3,190)
Accumulated other comprehensive income	14		16
APACHE SHAREHOLDERS’ EQUITY (DEFICIT)	(1,639)		3,255
Noncontrolling interest - Egypt	925		1,137
Noncontrolling interest - Altus	69		73
TOTAL EQUITY (DEFICIT)	(645)		4,465
	$	12,746	$	18,107

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

F-9

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)		APACHE SHAREHOLDERS’ EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)
	(In millions)		(In millions)
BALANCE AT DECEMBER 31, 2017	$	—	$	259	$	12,128	$	(2,088)	$	(2,887)	$	4	$	7,416	$	1,375	$	8,791
Net income attributable to common stock	—		—		—		40		—		—		40		—		40
Net income attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		245		245
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		1		1
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(345)		(345)

Common dividends ($1.00 per share)	—		—		(380)		—		—		—		(380)		—		(380)
Common stock activity, net	—		1		(29)		—		—		—		(28)		—		(28)
Treasury stock activity, net	—		—		—		—		(305)		—		(305)		—		(305)
Proceeds from Altus transaction	—		—		222		—		—		—		222		406		628
Compensation expense	—		—		160		—		—		—		160		—		160
Other	—		—		5		—		—		—		5		—		5
BALANCE AT DECEMBER 31, 2018	$	—	$	260	$	12,106	$	(2,048)	$	(3,192)	$	4	$	7,130	$	1,682	$	8,812
Net loss attributable to common stock	—		—		—		(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)
Pension & Postretirement benefit plans, net of tax	—		—		—		—		—		13		13		—		13
Common dividends ($1.00 per share)	—		—		(376)		—		—		—		(376)		—		(376)
Common stock activity, net	—		1		(22)		—		—		—		(21)		—		(21)
Compensation expense	—		—		61		—		—		—		61		—		61
Other	—		—		—		—		2		(1)		1		—		1
BALANCE AT DECEMBER 31, 2019	$	555	$	261	$	11,769	$	(5,601)	$	(3,190)	$	16	$	3,255	$	1,210	$	4,465
Net loss attributable to common stock	—		—		—		(4,860)		—		—		(4,860)		—		(4,860)
Net loss attributable to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(121)		(121)
Net income attributable to noncontrolling interest - Altus	—		—		—		—		—		—		—		1		1
Distributions to Altus Preferred Unit limited partners	(23)		—		—		—		—		—		—		—		—
Net income attributable to Altus Preferred Unit limited partners	76		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest - Egypt	—		—		—		—		—		—		—		(91)		(91)
Altus dividends	—		—		—		—		—		—		—		(5)		(5)
Pension & Postretirement benefit plans, net of tax	—		—		—		—		—		(2)		(2)		—		(2)
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		—		—		—		—
BALANCE AT DECEMBER 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)

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

F-10

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 also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

On January 4, 2021, Apache announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange, and APA will replace Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA” (the Holding Company Reorganization). The Holding Company Reorganization has not yet been implemented, but it is expected to be completed during the first half of 2021.

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. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of Apache and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’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 Apache’s consolidated balance sheet. ALTM qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of ALTM because it has concluded that it has a controlling financial interest in ALTM and is the primary beneficiary of the VIE. 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 1 3 —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, with the balance recorded separately as “Equity method interests” in the Company’s consolidated balance sheet and as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 6—Equity Method Interests for further detail.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 (see “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation), the estimate of income taxes (see Note 10—Income Taxes), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 18—Supplemental Oil and Gas Disclosures (Unaudited)).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’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 4—Derivative Instruments and Hedging Activities, Note 9—Debt and Financing Costs, Note 12—Retirement and Deferred Compensation Plans, and Note 13—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,
	2020		2019		2018
	(In millions)
Oil and gas proved property	$	4,319	$	1,484	$	328
Gathering, processing, and transmission facilities	68		1,295		56
Equity method investment	—		—		113
Divested unproved properties and leasehold	—		149		10
Goodwill	87		—		—
Inventory and other	27		21		4
Total Impairments	$	4,501	$	2,949	$	511

For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with fair value assessments.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 recorded proved property impairments totaling $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. Impairments totaling $68 million were similarly recorded for GPT facilities in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

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 2—Acquisitions and Divestitures.

For the year ended December 31, 2018, the Company recorded asset impairments totaling $511 million in connection with fair value assessments. Impairments totaling $328 million and $56 million were recorded for proved properties, and a gathering and processing facility in Oklahoma, respectively, which were written down to their fair values associated with U.S. assets to be divested. During the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea. As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement. Also in 2018, the Company recorded $113 million for the impairment of an equity method investment in the U.S. based on a negotiated sales price and $4 million for inventory write-downs in the U.S. for obsolescence.

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, 2020 and 2019, the Company had $262 million and $247 million, respectively, of cash and cash equivalents, of which approximately $24 million and $6 million, respectively, was held by Altus. The Company had no restricted cash as of December 31, 2020 and 2019.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 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. Apache 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,
	2020		2019		2018
	(In millions)
Allowance for credit loss at beginning of year	$	88	$	92	$	84
Additional provisions for the year	7		3		9
Uncollectible accounts written off, net of recoveries	—		(7)		(1)
Allowance for credit loss at end of year	$	95	$	88	$	92

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.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 Apache’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 2020. Similar assumptions were applied to impairments recorded in 2019 and 2018.

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,
	2020		2019		2018
	(In millions)
Proved properties:
U.S.	$	3,938	$	1,484	$	265
Egypt	374		—		63
North Sea	7		—		—
Total proved properties	$	4,319	$	1,484	$	328

Unproved properties:
U.S.	$	92	$	760	$	96
Egypt	8		8		—
North Sea	1		—		128
Total unproved properties	$	101	$	768	$	224

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. In addition, in 2018, unproved impairments of $10 million were recorded as a component of “Impairments” in connection with an agreement to sell certain unproved properties in the North Sea.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission Facilities

GPT facilities totaled $670 million and $799 million at December 31, 2020 and 2019, respectively, with accumulated depreciation for these assets totaling $323 million and $310 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.

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

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. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

During 2018, the Company recorded impairments of the entire net book value of certain GPT assets in the U.S. in the amount of $56 million associated with a proposed divestiture package.

The costs of GPT assets sold or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. A $2 million loss was recorded on the sale of power generators during 2020, and no gain or loss on the sales of GPT facilities was recognized during 2019 or 2018.

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, 2020 and 2019, with accumulated depreciation for these assets totaling $864 million and $817 million at December 31, 2020 and 2019, 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, and it is recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Apache assesses each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill. The fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to its implied fair value through a charge to expense.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.

The following presents the changes to goodwill for the years ended 2020, 2019, and 2018:


	Egypt		Total
	(In millions)
Goodwill at December 31, 2017	$	87	$	87
Impairments	—		—
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 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. This goodwill impairment has been recorded in “Impairments” in the Company’s statement of consolidated operations.

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 11—Commitments and Contingencies.

Revenue Recognition

The years ended 2019 and 2018 include the reclassification of $176 million and $357 million, respectively, from “Other” to “Purchased oil and gas sales,” both within “Revenues and Other” and the respective associated $142 million and $340 million purchased oil and gas costs from “Other” within “Revenues and Other” to “Purchased oil and gas costs” within “Operating Expenses” on the Company’s consolidated statement of operations to conform to the current-year presentation.

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.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company’s Egypt operations are conducted pursuant to production sharing contracts under which the contractor partners (Contractors) pay all operating and capital costs for exploring and developing defined concessions. A percentage of the production, generally up to 40 percent, is available to Contractors to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the Contractors and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the Contractors’ income taxes, which remain the liability of the Contractors under domestic law, are paid by EGPC on behalf of the Contractors out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

Refer to Note 1 7 —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 (collectively, Altus). 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 receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is 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 $670 million and $945 million as of December 31, 2020 and 2019, 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.

Derivative Instruments and Hedging Activities

Apache 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 4—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.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Earnings Per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. The Company uses the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream for shares of Altus’ common stock. The impact to net income (loss) attributable to common stock on an assumed conversion of the redeemable noncontrolling Preferred Units interest in Altus Midstream LP were anti-dilutive for the years ended December 31, 2020 and 2019.

Stock-Based Compensation

Apache grants 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 the Company’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 stock-based compensation plans and related accounting policies are defined and described more fully in Note 14—Capital Stock.

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

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 Apache’s organizational structure and operations. Reorganization efforts were substantially completed during 2020. Apache has incurred a cumulative total of $79 million of reorganization costs through December 31, 2020, all of which were paid in 2020.

The Company recorded $54 million, $50 million, and $28 million of TRS costs in 2020, 2019, and 2018, respectively. 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 and $2 million for employee termination benefits and consulting fees related to the reorganization, respectively. 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. Charges for 2018 include $22 million for consulting and legal fees related to divestitures and the Altus transaction, and $6 million related to employee separations.

New Pronouncements Issued But Not Yet Adopted

In October 2020, the FASB issued ASU 2020-10, “Codification Improvements,” which clarifies or improves disclosure requirements for various topics to align with Securities and Exchange Commission (SEC) regulations. This update is effective for the Company beginning in the first quarter of 2021 and will be applied retrospectively. The adoption and implementation of this ASU will not have a material impact on the Company’s financial statements.

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 the 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, with early adoption permitted, using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company is evaluating the effect of adoption of the ASU and does not believe it will have a material impact on its financial statements.

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

2. ACQUISITIONS AND DIVESTITURES

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

In the third quarter of 2019, Apache 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, Apache 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.

Suriname Joint Venture Agreement

In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. each hold a 50 percent working interest in Block 58. Pursuant to the agreement, Apache 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 Total S.A. on January 1, 2021. Apache will continue to operate the Keskesi exploration well until completion of drilling operations.

In connection with the agreement, Apache received $100 million from Total S.A. 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.

Leasehold, Property, and Other Acquisitions

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

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As part of the Altus transaction described below, Apache contributed options (Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream and/or its subsidiaries. As of December 31, 2019, four of the five Pipeline Options had been exercised to acquire various ownership interests in the associated Equity Method Interest Pipelines. The fifth Pipeline Option to acquire an equity interest in a separate intra-basin NGL pipeline was not exercised and expired on March 2, 2020. For discussion of the Equity Method Interest Pipelines, refer to Note 6—Equity Method Interests.

2018 Activity

Altus Transaction

In November 2018, Apache completed a transaction with Altus Midstream Company to create a pure-play, Permian Basin midstream C-corporation anchored by the Company’s GPT assets at Alpine High. Pursuant to the agreement, the Company contributed certain Alpine High midstream assets and the Pipeline Options to Altus and/or its subsidiaries. Altus Midstream Company contributed approximately $628 million of cash, net of transaction expenses. The transaction was accounted for by Altus as a reverse recapitalization. Under this method of accounting, Altus Midstream Company was treated as the “acquired” company, and Apache’s contributed assets of approximately $1.1 billion remained at historical cost, with no goodwill or other intangible assets recorded. Apache owns an approximate 79 percent ownership interest in Altus.

Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately. Apache recorded a noncontrolling interest of $406 million upon closing, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents approximately 21 percent third party ownership of the net assets in Altus at the time of the transaction. The cash contributions in excess of the noncontrolling interest were recognized as additional paid-in capital.

Other Activity

During 2018, the Company completed the sale of certain non-core assets and leasehold, primarily in the North Sea and Permian Basin, in multiple transactions for total cash proceeds of $138 million. The Company recognized gains of approximately $23 million during 2018 upon the closing of these transactions.

During 2018, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for cash proceeds of $133 million.

3. CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2020, 2019, and 2018. 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,
	2020		2019		2018
	(In millions)
Capitalized well costs at beginning of year	$	141	$	159	$	350
Additions pending determination of proved reserves	226		286		602
Divestitures and other	(38)		(100)		(82)
Reclassifications to proved properties	(56)		(179)		(647)
Charged to exploration expense	(76)		(25)		(64)
Capitalized well costs at end of year	$	197	$	141	$	159

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:


	2020		2019		2018
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	184	$	108	$	126
Exploratory well costs capitalized for a period greater than one year	13		33		33
Capitalized well costs at end of year	$	197	$	141	$	159

Number of projects with exploratory well costs capitalized for a period greater than one year	5		2		2

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2020, relate to onshore projects in Egypt. Drilling activity and testing has continued for these projects throughout 2020, and these projects are currently being evaluated for potential development.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2019, relate to separate onshore projects in the United States and Egypt. The costs related to the U.S. projects were charged to exploration expense in the current year based on management’s assessment and development efforts through year end.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2018, included $28 million related to exploratory drilling in Suriname. In December 2019, Apache entered into the joint venture agreement with Total S.A., pursuant to which Apache sold 50 percent of its ownership interest in Block 58 to Total S.A. Proceeds received from Total S.A. upon closing were applied against the carrying value of its Suriname properties.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2020, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:


	Total		2019		2018		2017 and Prior
	(In millions)

Egypt	$	13	$	4	$	9	$	—
	$	13	$	4	$	9	$	—

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

Apache 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, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2020, the Company had derivative positions with six 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, Apache may not realize the benefit of some of its derivative instruments resulting from changes in commodity prices, currency exchange rates, or interest rates.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 2020, 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
April—December 2021	NYMEX Henry Hub/IF Waha	37,580	$(0.43)	—	—
April—December 2021	NYMEX Henry Hub/IF HSC	—	—	37,580	$(0.07)
January—December 2022	NYMEX Henry Hub/IF Waha	43,800	$(0.45)	—	—
January—December 2022	NYMEX Henry Hub/IF HSC	—	—	43,800	$(0.08)

Embedded Derivatives

Altus Preferred Units Embedded Derivative

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

Pipeline Capacity Embedded Derivatives

During the fourth quarter of 2019 and first quarter of 2020, Apache entered into separate agreements to assign a portion of its contracted capacity under an existing transportation agreement to third parties. Embedded in these agreements are arrangements under which Apache has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. These features require bifurcation and measurement of the change in market values for each period. Unrealized gains or losses in the fair value of these features are recorded as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received will be deferred and reflected in income over the original tenure of the transportation agreement.

Fair Value Measurements

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


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount
	(In millions)
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
December 31, 2019
Assets:
Pipeline capacity embedded derivative	$	—	$	8	$	—	$	8	$	—	$	8
Foreign currency derivative instruments	—		1		—		1		—		1

Liabilities:
Preferred Units embedded derivative	—		—		103		103		—		103

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

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the December 31, 2020 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, 2020

Valuation Technique

Significant Unobservable Inputs

Range/Value

(In millions)

Preferred Units embedded derivative

139

Option Model

Altus’ Imputed Interest Rate

7.32-11.73%

Interest Rate Volatility

37.08%

A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of December 31, 2020, while a one percent decrease would lead to a similar decrease in value as of December 31, 2020. The assumed expected timing until exercise of the exchange option at December 31, 2020 was 5.45 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:


	2020		2019
	(In millions)
Current Assets: Other current assets	$	6	$	2
Noncurrent Assets: Deferred charges and other	5		7
Total derivative assets	$	11	$	9


Deferred Credits and Other Noncurrent Liabilities: Other	$	192	$	103
Total derivative liabilities	$	192	$	103

F-25

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,
	2020		2019		2018
	(In millions)
Realized:
Commodity derivative instruments	$	(135)	$	27	$	(81)
Amortization of put premium, realized loss	—		—		(39)
Foreign currency derivative instruments	(1)		—		—
Treasury-lock	—		(18)		—
Realized gain (loss), net	(136)		9		(120)
Unrealized:
Commodity derivative instruments	11		(44)		103
Pipeline capacity embedded derivatives	(61)		8		—
Foreign currency derivative instruments	(1)		1		—
Preferred Units embedded derivative	(36)		(9)		—
Unrealized gain (loss), net	(87)		(44)		103
Derivative instrument losses, net	$	(223)	$	(35)	$	(17)

Derivative instrument gains and losses are recorded in “Derivative instrument 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 loss to net cash provided by operating activities.”

5. OTHER CURRENT ASSETS

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


	2020		2019
	(In millions)
Inventories	$	492	$	502
Drilling advances	113		92
Prepaid assets and other	71		58
Total Other current assets	$	676	$	652

6. EQUITY METHOD INTERESTS

As of December 31, 2020 and 2019, 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		2020		2019
			(In millions)
Gulf Coast Express Pipeline LLC	16.0	%	$	284	$	291
EPIC Crude Holdings, LP	15.0	%	176		163
Permian Highway Pipeline LLC	26.7	%	615		311
Shin Oak Pipeline (Breviloba, LLC)	33.0	%	480		493
Total Altus equity method interests			$	1,555	$	1,258

As of December 31, 2020 and 2019, unamortized basis differences included in the equity method interest balances were $38 million and $30 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.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2020 and 2019:


	Gulf Coast Express Pipeline LLC		EPIC Crude Holdings, LP		Permian Highway Pipeline LLC		Breviloba, LLC		Total
	(In millions)
Balance at December 31, 2018	$	91	$	—	$	—	$	—	$	91
Acquisitions	15		52		162		442		671
Capital contributions	184		123		147		47		501
Distributions	(16)						(9)		(25)
Capitalized interest(1)	—		—		2		—		2
Equity income (loss), net	17		(11)		—		13		19
Accumulated other comprehensive loss	—		(1)		—		—		(1)
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

(1)Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million and $2 million of related interest expense during 2020 and 2019, respectively, which are included in the basis of the PHP equity interest.

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,
	2020		2019(1)		2018(2)
	(In millions)
Operating revenues	$	707	$	302	$	3

Operating income (loss)	331		121		(6)
Net income (loss)	256		120		(6)
Other comprehensive loss	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 year ended December 31, 2019 for comparability.

(2)Although Altus’ interest in Gulf Coast Express Pipeline LLC was acquired in December 2018, the combined financial results are presented for the year ended December 31, 2018 for comparability.

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


	2020		2019
	(In millions)
Current assets	$	260	$	441
Noncurrent assets	7,678		6,435
Total assets	$	7,938	$	6,876

Current liabilities	$	206	$	478
Noncurrent liabilities	1,191		958
Equity	6,541		5,440
Total liabilities and equity	$	7,938	$	6,876

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. OTHER CURRENT LIABILITIES

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


	2020		2019
	(In millions)
Accrued operating expenses	$	91	$	143
Accrued exploration and development	167		319
Accrued gathering, processing, and transmission - Altus	—		17
Accrued compensation and benefits	170		212
Accrued interest	140		135
Accrued income taxes	25		51
Current asset retirement obligation	56		47
Current operating lease liability	116		169
Other	97		56
Total Other current liabilities	$	862	$	1,149

8. ASSET RETIREMENT OBLIGATION

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


	For the Year Ended December 31,
	2020		2019
	(In millions)
Asset retirement obligation at beginning of year	$	1,858	$	1,932
Liabilities incurred	10		41

Liabilities divested	(26)		(56)
Liabilities settled	(30)		(56)
Accretion expense	109		107
Revisions in estimated liabilities	23		(110)

Asset retirement obligation at end of year	1,944		1,858
Less current portion	(56)		(47)
Asset retirement obligation, long-term	$	1,888	$	1,811

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’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 2020 and 2019, the Company recorded $10 million and $41 million, respectively, in abandonment liabilities resulting from Apache’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. 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. During 2019, approximately $110 million net abandonment costs were revised downward to reflect changes in estimates of timing and costs, primarily in the North Sea.

9. DEBT AND FINANCING COSTS

Overview

All of the Company’s debt is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures 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.

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In August 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. 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, repay notes that matured in September 2018, and for general corporate purposes.

Also in August 2018, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.

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, the Company 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 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, the Company 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 the Company’s senior revolving credit facility, and for general corporate purposes.

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

During 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. The repurchases were financed by borrowings under the Company’s revolving credit facility.

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

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	December 31,
	2020		2019
	(In millions)

3.625% notes due 2021(1)	$	—	$	293
3.25% notes due 2022(2)	213		463
2.625% notes due 2023(2)	123		181
4.625% notes due 2025(2)	500		—
7.7% notes due 2026	79		79
7.95% notes due 2026	133		133
4.875% due 2027(2)	750		—
4.375% notes due 2028(2)	993		1,000
7.75% notes due 2029(2)(3)	235		247
4.25% notes due 2030(2)	580		600
6.0% notes due 2037(2)	443		467
5.1% notes due 2040(2)	1,333		1,499
5.25% notes due 2042(2)	399		500
4.75% notes due 2043(2)	1,133		1,413
4.25% notes due 2044(2)	559		753
7.375% debentures due 2047	150		150
5.35% notes due 2049(2)	390		400
7.625% debentures due 2096	39		39
Notes and debentures before unamortized discount and debt issuance costs(4)	8,052		8,217
Commercial paper	—		—
Altus credit facility(5)	624		396
Apache credit facility(5)	150		—
Finance lease obligations	38		48
Unamortized discount	(35)		(42)
Debt issuance costs	(57)		(53)
Total debt	8,772		8,566
Current maturities	(2)		(11)
Long-term debt	$	8,770	$	8,555

(1)On November 3, 2020, Apache redeemed the 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.

(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 the Company’s notes and debentures were $8.5 billion and $8.4 billion as of December 31, 2020 and 2019, respectively. Apache 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, 2020 are as follows:


	(In millions)
2021	$	—
2022	213
2023	123
2024	—
2025	500
Thereafter	7,216
Notes and debentures, excluding discounts and debt issuance costs	$	8,052

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2020 and 2019, there were no outstanding borrowings under these facilities. As of December 31, 2020, there were £34 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2019, there were £22 million and $3 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. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2020. The facility is for general corporate purposes and available committed borrowing capacity supports Apache’s commercial paper program. 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. As of December 31, 2019, there were no borrowings or letters of credit outstanding under this facility. The £633 million in outstanding letters of credit were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced the Company’s credit rating from BBB to BB+ on March 26, 2020.

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 London Inter-bank Offered Rate (LIBOR), plus a margin. The Company also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2020, 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 the Company 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 the Company 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 United States 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 $1.7 billion as of December 31, 2020. 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, 2020 and December 31, 2019, there were $624 million and $396 million, respectively, of borrowings, and no letters of credit outstanding under this facility.

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache 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, 2020 was less than 4.00:1.00.

The terms of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Apache and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13—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 Apache or any of Apache’s other subsidiaries.

Commercial Paper Program

Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in the Company’s credit ratings during 2020, the Company does not expect that its commercial paper program will be cost competitive with its other financing alternatives and does not anticipate using it under such circumstances. As of December 31, 2020 and 2019, the Company had no commercial paper outstanding.

Financing Costs, Net

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


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Interest expense	$	438	$	430	$	441
Amortization of debt issuance costs	8		7		9
Capitalized interest	(12)		(37)		(44)
Loss (gain) on extinguishment of debt	(160)		75		94
Interest income	(7)		(13)		(22)
Financing costs, net	$	267	$	462	$	478

As of December 31, 2020, the Company had $57 million of debt issuance costs, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $7 million, $2 million, and $3 million was recorded as interest expense in 2020, 2019, and 2018, respectively.

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. INCOME TAXES

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


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
U.S.	$	(4,581)	$	(4,397)	$	(723)
Foreign	(259)		1,389		1,681
Total	$	(4,840)	$	(3,008)	$	958

The total income tax provision consists of the following:


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Current income taxes:
Federal	$	(2)	$	1	$	(1)
State	—		—		—
Foreign	178		659		895
	176		660		894
Deferred income taxes:
Federal	—		67		(65)
State	—		—		2
Foreign	(112)		(53)		(159)
	(112)		14		(222)
Total	$	64	$	674	$	672

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,
	2020		2019		2018
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	(1,016)	$	(631)	$	201
State income tax, less federal effect(1)	—		1		2
Taxes related to foreign operations	97		328		436
Tax credits	(13)		(6)		(13)

Tax on deemed repatriation of foreign earnings	—		—		103
Foreign tax credits	—		—		(336)


Change in U.S. tax rate	—		—		161
Net change in tax contingencies	1		1		(2)
Goodwill impairment	35		—		—
Sale of North Sea assets	—		—		(30)
Valuation allowances(1)	965		972		118
All other, net	(5)		9		32
	$	64	$	674	$	672

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

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:


	2020		2019
	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,306	$	2,108
Capital losses	633		626

Tax credits and other tax incentives	33		32
Foreign tax credits	2,241		2,241
Accrued expenses and liabilities	93		97
Asset retirement obligation	654		618
Property & equipment	261		—
Investment in Altus Midstream LP	76		107
Net interest expense limitation	252		162
Lease liability	79		108
Other	1		88
Total deferred tax assets	6,629		6,187
Valuation allowance	(5,991)		(4,959)
Net deferred tax assets	638		1,228
Deferred tax liabilities:
Deferred income	—		1

Equity investments	4		—

Property and equipment	750		1,432
Right-of-use asset	74		106
Other	13		6
Total deferred tax liabilities	841		1,545
Net deferred income tax liability	$	203	$	317

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


	2020		2019
	(In millions)
Assets:

Deferred charges and other	$	12	$	29
Liabilities:

Income taxes	215		346
Net deferred income tax liability	$	203	$	317

On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) which provides guidance for the application of ASC Topic 740, Income Taxes, for the income tax effects of the Tax Cuts and Jobs Act (the TCJA). SAB 118 provides a measurement period which should not extend beyond 1 year of the enactment date of the TCJA. In 2018, the Company recorded an additional $103 million deferred tax expense attributable to the deemed repatriation of foreign earnings. This deferred tax expense combined with the provisional amount recorded in 2017 were fully offset by available foreign tax credits. The Company completed its analysis of the income tax effects of the TCJA in the fourth quarter of 2018.

The Company has recorded an increase in valuation allowance against certain deferred tax assets, primarily driven by asset impairments. The Company has assessed the future potential to realize these deferred tax assets and has concluded that it is more likely than not that these deferred tax assets will not be realized based on current economic conditions and expectations for the future.

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In 2020, 2019, and 2018, the Company’s valuation allowance increased by $1.0 billion, $1.0 billion, and $131 million, respectively, as detailed in the table below:


	2020		2019		2018
	(In millions)
Balance at beginning of year	$	4,959	$	3,947	$	3,816
State(1)	67		41		15
U.S.	960		971		124
Foreign	5		—		(8)

Balance at end of year	$	5,991	$	4,959	$	3,947

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

On December 31, 2020, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

8,859

2020 - Indefinite

State

6,566

Various

The Company has a U.S. net operating loss carryforward of $8.9 billion, which includes $186 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 TCJA. The Company also has a net interest expense carryover of $1.1 billion under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.8 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 carryforward because it is more likely than not that these attributes will not be realized.

On December 31, 2020, 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 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:


	2020		2019		2018
	(In millions)
Balance at beginning of year	$	82	$	24	$	26
Additions based on tax positions related to prior year	—		49		—
Additions based on tax positions related to the current year	11		9		—
Reductions for tax positions of prior years	—		—		(2)
Balance at end of year	$	93	$	82	$	24

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, 2020, 2019, and 2018, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2020, 2019, and 2018, the Company had an accrued liability for interest and penalties of $3 million, $2 million, and $1 million, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In 2020, 2019, and 2018, the Company recorded an $11 million net increase, $58 million net increase, and a $2 million net reduction, 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.			2019

In 2020, the Company early adopted ASU 2019-12, “Simplifying the Accounting for Income Taxes.” The Company’s early adoption of ASU 2019-12 using the prospective transition approach did not result in a material impact on the consolidated financial statements.

11. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. As of December 31, 2020, the Company has an accrued liability of approximately $70 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Starting in November of 2013 and continuing into 2020, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. Some of the cases have been remanded to state court with the remand orders being appealed. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

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

Australian Operations Divestiture Dispute

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

Canadian Operations Divestiture Dispute

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

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The remand decision, and further activity in the cases, has been stayed pending further appellate review.

On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

Castex Lawsuit

In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs and interest was entered against the Company. The Company’s 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 in excess of $250 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. The amount of this claim is not yet reasonably determinable. While adverse judgments against the Company are possible, the Company intends to vigorously defend these lawsuits and claims.

Stockholder 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. Other lawsuits have followed with similar allegations. The Company believes that all plaintiffs’ claims lack merit and intends to vigorously defend these lawsuits.

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, 2020, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and responding to the information request. The EPA has not commenced enforcement proceedings, and at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

Additionally, 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 relating to several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and responding to the information request. The EPA has not commenced enforcement proceedings, and at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.

The Company is not aware of any environmental claims existing as of December 31, 2020 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Asset Retirement Obligations

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.

F-39

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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” within “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 $149 million and $222 million in 2020 and 2019, respectively. Apache elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases, which is primarily related to drilling activities in Block 58 offshore Suriname, was $80 million and $18 million in 2020 and 2019, respectively.

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 “Other” within “Property 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 and $7 million in 2020 and 2019, respectively. Interest on the Company’s finance lease assets was $2 million and $3 million in 2020 and 2019, respectively.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2020:


	Operating Leases		Finance Leases
Weighted average remaining lease term	3.7 years		12.7 years
Weighted average discount rate	4.2	%	4.4	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

At December 31, 2020, 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)
	(In millions)
2021	$	120	$	3	$	236
2022	70		3		203
2023	33		3		203
2024	27		4		160
2025	7		4		159
Thereafter	25		29		600
Total future minimum payments	282		46		$	1,561
Less: imputed interest	(21)		(8)		N/A
Total lease liabilities	261		38		N/A
Current portion	116		2		N/A
Non-current portion	$	145	$	36	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 agreement 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 $120 million, $111 million, and $132 million in 2020, 2019, and 2018, respectively.

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 was $41 million and $78 million in 2020 and 2019, respectively.

As a result of electing the transitional practical expedient to apply the provisions of the standard at its adoption date instead of the earliest comparative period presented, below are the required ASU Leases (Topic 840) disclosures for prior periods:


	Operating Leases(1)		Finance Leases(2)
	(In millions)
Year ended December 31, 2018
2019	$	61	$	1
2020-2021	64		3
2022-2023	53		4
2024 & Beyond	42		32
Total	$	220	$	40

(1)Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Total rent expense, net of amounts capitalized and sublease income was $76 million in 2018.

(2)This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million as of December 31, 2018.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation 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 change in control of ownership of Apache Corporation, 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 Apache 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 $43 million, $52 million, and $52 million for 2020, 2019, and 2018, respectively.

Apache 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, 2020, 2019, and 2018, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.


	2020						2019						2018
	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	$	199		$	20		$	187		$	27		$	216		$	27
Service cost	3			1			3			2			4			2
Interest cost	4			—			5			1			5			1
Foreign currency exchange rates	8			—			7			—			(11)			—
Actuarial losses (gains)	30			1			15			(9)			(11)			(2)
Plan settlements	—			—			(14)			—			(11)			—
Benefits paid	(11)			(4)			(4)			(2)			(5)			(3)
Retiree contributions	—			2			—			1			—			2
Projected benefit obligation at end of year	233			20			199			20			187			27
Change in Plan Assets
Fair value of plan assets at beginning of year	228			—			208			—			238			—
Actual return on plan assets	31			—			25			—			(6)			—
Foreign currency exchange rates	9			—			8			—			(13)			—
Employer contributions	5			2			5			1			5			2
Plan settlements	—			—			(14)			—			(11)			—
Benefits paid	(11)			(4)			(4)			(2)			(5)			(4)
Retiree contributions	—			2			—			1			—			2
Fair value of plan assets at end of year	262			—			228			—			208			—
Funded status at end of year	$	29		$	(20)		$	29		$	(20)		$	21		$	(27)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	29			(18)			29			(18)			21			(25)
	$	29		$	(20)		$	29		$	(20)		$	21		$	(27)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(11)		$	16		$	(7)		$	19		$	(13)		$	10

Weighted Average Assumptions used as of 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	2.20		%	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		%

As of December 31, 2020, 2019, and 2018, the accumulated benefit obligation for the U.K. Pension Plan was $207 million, $181 million, and $167 million, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Apache’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
	2020		2020		2019
Asset Category
Equity securities:

Overseas quoted equities	19	%	19	%	23	%
Total equity securities	19	%	19	%	23	%
Debt securities:
U.K. government bonds	65	%	64	%	62	%
U.K. corporate bonds	16	%	16	%	15	%
Total debt securities	81	%	80	%	77	%
Cash	—		1	%	—
Total	100	%	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of Apache. The fair value of plan assets at December 31, 2020 and 2019 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, 2020 and 2019:


	December 31,
	2020		2019
	(In millions)
Equity securities:

Overseas quoted equities	$	49	$	52
Total equity securities	49		52
Debt securities:
U.K. government bonds	168		140
U.K. corporate bonds	43		35
Total debt securities	211		175
Cash	2		1
Fair value of plan assets	$	262	$	228

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, 2020, 2019, and 2018:


	2020						2019						2018
	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		$	2		$	4		$	2
Interest cost	4			—			5			1			5			1
Expected return on assets	(5)			—			(5)			—			(7)			—
Amortization of gain	—			(1)			—			(1)			—			—
Settlement loss	—			—			—			—			1			—
Net periodic benefit cost	$	2		$	—		$	3		$	2		$	3		$	3
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	2.10		%	3.00		%	2.90		%	4.13		%	2.60		%	3.44		%
Salary increases	4.30		%	N/A			4.70		%	N/A			4.70		%	N/A
Expected return on assets	2.20		%	N/A			2.80		%	N/A			2.90		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.50		%	N/A			6.75		%
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 2021. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits
	(In millions)
2021	$	5	$	2
2022	6		2
2023	7		2
2024	6		2
2025	6		2
Years 2026-2030	36		6

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. REDEEMABLE NONCONTROLLING INTEREST - ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act 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 $139 million as of December 31, 2020. 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. See Note 4—Derivative Instruments and Hedging Activities for more detail.

F-46

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, 2020 and 2019 is as follows:


	Units Outstanding	Financial Position(1)
	(In millions, except unit data)
Redeemable noncontrolling interest — Preferred Units: at December 31, 2018	—	$	—
Issuance of Preferred Units, net	625,000	517
Distribution of in-kind additional Preferred Units	13,163	—
Allocation of Altus Midstream net income	N/A	38
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2019	638,163	555

Distribution of in-kind additional Preferred Units	22,531	—
Cash distributions to Altus Preferred Unit limited partners	—	(23)
Allocation of Altus Midstream LP net income	N/A	76
Redeemable noncontrolling interest - Altus Preferred Unit limited partners: at December 31, 2020	660,694	608
Preferred Units embedded derivative		139
		$	747

(1)The Preferred Units are redeemable at Altus Midstream’s option at a redemption price (the Redemption Price), which as of December 31, 2020 was 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, 2020, the Redemption Price would have been based on 1.3 times multiple of invested capital, which was $813 million and greater than using an 11.5 percent internal rate of return, which was $717 million.

N/A - not applicable.

14. CAPITAL STOCK

Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2020, 2019, and 2018:


	For the Year Ended December 31,
	2020	2019	2018
Balance, beginning of year	376,062,670	374,696,222	380,954,864
Shares issued for stock-based compensation plans:
Treasury shares issued	17,448	31,701	2,454
Common shares issued	1,402,512	1,334,747	1,566,237
Treasury shares acquired	—	—	(7,827,333)
Balance, end of year	377,482,630	376,062,670	374,696,222

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Net Income (Loss) per Common Share

The following table provides a reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2020, 2019, and 2018:


	2020					2019					2018
	Loss		Shares	Per Share		Loss		Shares	Per Share		Income		Shares	Per Share
	(In millions, except per share amounts)
Basic:


Income (loss) attributable to common stock	$	(4,860)	378	$	(12.86)	$	(3,553)	377	$	(9.43)	$	40	382	$	0.11
Effect of Dilutive Securities:
Stock options and other	$	—	—	$	—	$	—	—	$	—	$	—	2	$	—
Diluted:


Income (loss) attributable to common stock	$	(4,860)	378	$	(12.86)	$	(3,553)	377	$	(9.43)	$	40	384	$	0.11

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.5 million, 5.0 million, and 5.6 million for the years ended December 31, 2020, 2019, and 2018, respectively. The impact to net income (loss) attributable to common stock on an assumed conversion of the redeemable noncontrolling Preferred Units interest in Altus Midstream LP was anti-dilutive for the years ended December 31, 2020 and 2019.

Stock Repurchase Program

In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and, through December 31, 2020, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during the year ended December 31, 2020.

Common Stock Dividend

In the first quarter of 2020, the 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. For the year ended December 31, 2020, the Company declared common stock dividends of $0.10 per share. For each of the years ended December 31, 2019 and 2018, the Company declared common stock dividends of $1.00 per share.

Stock Compensation Plans

The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. 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, 2020, 14.1 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.

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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,
	2020		2019		2018
	(In millions)
Stock-settled and cash-settled compensation expensed	$	40	$	110	$	157
Stock-settled and cash-settled compensation capitalized	7		28		37
Total stock-settled and cash-settled compensation costs	$	47	$	138	$	194

Stock Options

As of December 31, 2020, the Company had outstanding options to purchase shares of its 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), (collectively, 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 Apache’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, 2020, 2019, and 2018:


	2020			2019			2018
	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	4,298	$	75.24	4,872	$	75.95	4,593	$	83.36
Granted	—	—		—	—		812	45.93
Exercised	—	—		—	—		(29)	41.79
Forfeited	(37)	44.98		(80)	34.58		(121)	74.58
Expired	(724)	92.14		(494)	88.82		(383)	104.21
Outstanding, end of year(1)	3,537	72.10		4,298	75.24		4,872	75.95
Expected to vest(2)	150	45.77		495	49.11		1,274	48.74
Exercisable, end of year(3)	3,387	73.26		3,803	78.64		3,598	85.59

(1)As of December 31, 2020, options outstanding had a weighted average remaining contractual life of 3.6 years and no intrinsic value.

(2)As of December 31, 2020, options expected to vest had a weighted average remaining contractual life of 7.0 years and no intrinsic value.

(3)As of December 31, 2020, options exercisable had a weighted average remaining contractual life of 3.4 years and no intrinsic value.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model, a Level 2 fair value measurement. The following table summarizes specific assumptions used in the Company’s valuation:

2020

2019

2018

Expected volatility

N/A

33.74%

Expected dividend yields

N/A

2.16%

Expected term (in years)

N/A

Risk-free rate

N/A

2.42%

Weighted-average grant-date fair value

N/A

13.15

N/A - not applicable.

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Assumptions related to the expected volatilities are based on the Company’s historical volatility of its common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

There were no options issued and no options exercised during the years ended December 31, 2020 and 2019. The intrinsic values of options exercised during the year ended December 31, 2018 was approximately $0.1 million. As of December 31, 2020, total compensation cost related to non-vested options not yet recognized was nil because they fully vest on January 5, 2021.

Restricted Stock Units and Restricted Stock Phantom Units

The Company has 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 the Company’s 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. The cash-settled awards compensation expense 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, 2020, 2019, and 2018, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $39 million, $104 million, and $101 million, respectively. As of December 31, 2020, 2019, and 2018, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $6 million, $24 million, and $29 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2020, 2019, and 2018:


	2020			2019			2018
	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	2,448	$	46.65	3,153	$	55.54	4,920	$	56.67
Granted	1,352	24.60		1,479	36.81		608	45.59
Vested(3)	(1,933)	48.65		(1,899)	53.99		(2,023)	55.10
Forfeited	(315)	30.09		(285)	45.06		(352)	56.69
Non-vested, end of year(1)(2)	1,552	28.43		2,448	46.65		3,153	55.54

(1)As of December 31, 2020, there was $14 million of total unrecognized compensation cost related to 1,551,807 unvested stock-settled restricted stock units.

(2)As of December 31, 2020, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years.

(3)The grant date fair values of the stock-settled awards vested during 2020, 2019, and 2018 were approximately $94 million, $103 million, and $111 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, 2020, 2019, and 2018:


	For the Year Ended December 31,
	2020	2019	2018
	(In thousands)
Non-vested, beginning of year	5,384	1,818	59
Adjustment for ALTM reverse stock split(1)	(1,246)	—	—
Granted(2)	3,462	4,831	1,973
Vested	(1,618)	(616)	(38)
Forfeited	(1,559)	(649)	(176)
Non-vested, end of year(3)	4,423	5,384	1,818

(1)On June 30, 2020, Altus 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 2020 and 2019 included 3,378,486 and 3,401,477 awards, respectively, based on the per-share market price of Apache common stock and 83,239 and 1,429,135 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, 2020 was approximately $28 million.

In January 2021, the Company awarded 1,354,349 restricted stock units and 4,360,656 restricted stock phantom units based on Apache’s weighted-average per-share market price of $16.18 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 $22 million and $71 million, respectively, and was calculated based on the per-share fair market value of a share of the Company’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 the Company’s common stock.

Also during January 2021, the Company awarded 56,836 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $48.84. 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 $3 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.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 Apache 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, 2020, 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 111,126 restricted stock units were outstanding as of December 31, 2020. 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 704,483 phantom units were outstanding as of December 31, 2020. 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. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,301,893 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,603,786 phantom units could be awarded.

•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 1,410,404 phantom units were outstanding as of December 31, 2020, from which a minimum of zero to a maximum of 2,820,808 phantom 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 cost charged to expense under the performance programs was a credit of $8 million during 2020 and expenses of $24 million and $38 million during 2019 and 2018, respectively. Capitalized compensation costs under the performance programs was a credit of $1 million during 2020 and expenses of $3 million and $7 million during 2019 and 2018, respectively.

The following table summarizes stock-settled conditional restricted stock unit activity for the year ended December 31, 2020:


	Units	Weighted Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested, beginning of year	781	$	52.69
Granted	18	62.31
Vested	(445)	41.10
Forfeited	(16)	56.66
Expired	(227)	70.70
Non-vested, end of year(2)(3)	111	63.15

(1)The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group.

(2)As of December 31, 2020, there was no unrecognized compensation cost related to 111,126 unvested stock-settled conditional restricted stock units.

(3)As of December 31, 2020, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.0 years.

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2020:


						Units
						(In thousands)
Non-vested, beginning of year						2,320
Granted						1,687
Vested						(2)
Forfeited						(542)
Expired						(46)
Non-vested, end of year(1)						3,417

(1)As of December 31, 2020, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $14 million.

In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Payout for 50 percent of the shares is based upon measurement of TSR of Apache 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 1,911,517 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 3,823,034 units. These phantom units represent a hypothetical interest in the Company’s stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $23.73 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $16.18 based on the weighted-average fair market value of a share of common stock of the Company as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.

15. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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


	As of December 31,
	2020		2019		2018
	(In millions)
Share of equity method interests other comprehensive loss	$	(1)	$	(1)	$	—
Pension and postretirement benefit plan (Note 12)	15		17		4
Accumulated other comprehensive income	$	14	$	16	$	4

16. MAJOR CUSTOMERS

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)

17. BUSINESS SEGMENT INFORMATION

As of December 31, 2020, Apache is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s Upstream business explores for, develops, and produces natural gas, crude oil and natural gas liquids. During 2018, Apache established a new reporting segment for its U.S. midstream business separate from its upstream oil and gas development activities. 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)
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-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)
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

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)
2018
Oil revenues	$	2,396	$	1,179	$	2,271	$	—	$	—	$	5,846
Natural gas revenues	339		122		458		—		—		919
Natural gas liquids revenues	13		20		550		—		—		583
Oil, natural gas, and natural gas liquids production revenues	2,748		1,321		3,279		—		—		7,348
Purchased oil and gas sales	—		—		357		—		—		357
Midstream service affiliate revenues	—		—		—		77		(77)		—
	2,748		1,321		3,636		77		(77)		7,705
Operating Expenses:
Lease operating expenses	428		341		670		—		—		1,439
Gathering, processing, and transmission	47		42		282		54		(77)		348
Purchased oil and gas costs	—		—		340		—		—		340
Taxes other than income	—		—		207		8		—		215
Exploration	88		192		219		—		4		503
Depreciation, depletion, and amortization	745		375		1,266		19		—		2,405
Asset retirement obligation accretion	—		75		32		1		—		108
Impairments	63		10		438		—		—		511
	1,371		1,035		3,454		82		(73)		5,869
Operating Income (Loss)	$	1,377	$	286	$	182	$	(5)	$	(4)	1,836
Other Income (Expense):
Gain on divestitures, net											23
Derivative instrument losses, net											(17)
Other											53
General and administrative											(431)
Transaction, reorganization, and separation											(28)
Financing costs, net											(478)
Income Before Income Taxes											$	958

Total Assets(3)	$	4,260	$	2,456	$	12,962	$	1,857	$	47	$	21,582
Net Property and Equipment	$	2,856	$	2,148	$	12,145	$	1,227	$	45	$	18,421
Additions to Net Property and Equipment	$	594	$	223	$	2,544	$	545	$	8	$	3,914

(1)Includes revenue from non-customers for the years ended December 31, 2020, 2019, and 2018 of:


	For the Year Ended December 31,
	2020		2019		2018
	(In millions)
Oil	$	95	$	410	$	592
Natural gas	14		40		58
Natural gas liquids	—		1		2

(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)

18. 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)
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)
2018
Oil and gas production revenues	$	3,279	$	2,748	$	1,321	$	—	$	7,348
Operating cost:
Depreciation, depletion, and amortization(2)	1,206		688		371		—		2,265
Asset retirement obligation accretion	32		—		75		—		107
Lease operating expenses	670		428		341		—		1,439
Gathering, processing, and transmission	282		47		42		—		371
Exploration expenses	219		88		192		4		503
Impairments related to oil and gas properties	265		63		10		—		338
Production taxes(3)	203		—		—		—		203
Income tax	87		645		116		—		848
	2,964		1,959		1,147		4		6,074
Results of operations	$	315	$	789	$	174	$	(4)	$	1,274

(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 17—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 17—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)
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)
2018
Acquisitions:
Proved	$	—	$	6	$	—	$	—	$	6
Unproved	111		16		—		—		127
Exploration	640		175		113		12		940
Development	1,791		457		133		—		2,381
Costs incurred(1)	$	2,542	$	654	$	246	$	12	$	3,454
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	23	$	—	$	11	$	2	$	36
Asset retirement costs	93		—		(62)		—		31
(2) Includes a noncontrolling interest in Egypt.

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)
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

2019
Proved properties	$	20,291	$	11,614	$	8,635	$	—	$	40,540
Unproved properties	509		109		10		38		666
	20,800		11,723		8,645		38		41,206
Accumulated DD&A	(11,783)		(9,377)		(6,700)		—		(27,860)
	$	9,017	$	2,346	$	1,945	$	38	$	13,346

(1)Includes a noncontrolling interest in Egypt..

Oil and Gas Reserve Information

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, 2017	304,279	124,568	92,598	521,445
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
Proved undeveloped reserves:
December 31, 2017	31,904	16,198	14,013	62,115
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

Total proved reserves:
Balance December 31, 2017	336,183	140,766	106,611	583,560
Extensions, discoveries and other additions	61,976	22,473	15,682	100,131
Purchases of minerals in-place	140	—	—	140
Revisions of previous estimates	(14,334)	(9,556)	10,613	(13,277)
Production	(38,252)	(34,185)	(17,137)	(89,574)
Sales of minerals in-place	(47)	—	—	(47)
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

(1)Includes proved reserves of 36 MMbbls, 38 MMbbls, 40 MMbbls, and 47 MMbbls as of December 31, 2020, 2019, 2018, and 2017, 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, 2017	171,005	685	2,025	173,715
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
Proved undeveloped reserves:
December 31, 2017	29,559	39	353	29,951
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

Total proved reserves:
Balance December 31, 2017	200,564	724	2,378	203,666
Extensions, discoveries and other additions	60,990	144	1,444	62,578
Purchases of minerals in-place	40	—	—	40
Revisions of previous estimates	(9,250)	31	(819)	(10,038)
Production	(20,969)	(337)	(434)	(21,740)
Sales of minerals in-place	(5)	—	—	(5)
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

(1) Includes proved reserves of 281 Mbbls, 252 Mbbls, 187 Mbbls, and 241 Mbbls as of December 31, 2020, 2019, 2018, and 2017, 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, 2017	1,347,009	540,667	83,342	1,971,018
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
Proved undeveloped reserves:
December 31, 2017	297,226	47,255	11,063	355,544
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

Total proved reserves:
Balance December 31, 2017	1,644,235	587,922	94,405	2,326,562
Extensions, discoveries and other additions	704,135	79,394	55,274	838,803
Purchases of minerals in-place	906	—	—	906
Revisions of previous estimates	(239,204)	(38,892)	(21,933)	(300,029)
Production	(216,538)	(119,286)	(16,595)	(352,419)
Sales of minerals in-place	(41)	—	—	(41)
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

(1) Includes proved reserves of 141 Bcf, 153 Bcf, 170 Bcf, and 196 Bcf as of December 31, 2020, 2019, 2018, and 2017, 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, 2017	699,786	215,364	108,513	1,023,663
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
Proved undeveloped reserves:
December 31, 2017	111,001	24,112	16,210	151,323
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

Total proved reserves:
Balance December 31, 2017	810,787	239,476	124,723	1,174,986
Extensions, discoveries and other additions	240,322	35,849	26,338	302,509
Purchases of minerals in-place	331	—	—	331
Revisions of previous estimates	(63,451)	(16,007)	6,139	(73,319)
Production	(95,312)	(54,402)	(20,337)	(170,051)
Sales of minerals in-place	(59)	—	—	(59)
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

(1) Includes include total proved reserves of 59 MMboe, 64 MMboe, 68 MMboe, and 80 MMboe as of December 31, 2020, 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt.

During 2020, Apache 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.

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2019, Apache 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.

During 2018, Apache added approximately 303 MMboe from extensions, discoveries, and other additions. The Company recorded 240 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Yeso, Barnett, and Wolfcamp drilling programs in the Permian Basin (217 MMboe) and Woodford and Austin Chalk drilling activity in the Midcontinent region (20 MMboe). The Company’s international assets contributed 62 MMboe of exploration and development adds during 2018. Egypt contributed 36 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, Matruh, and West Kalabsha concessions. The North Sea contributed 26 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 73 MMboe. Downward revisions related to changes in product prices accounted for 24 MMboe, interest revisions accounted for 5 MMboe, and engineering and performance downward revisions accounted for 44 MMboe.

Approximately 10 percent of the Company’s year-end 2020 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, 2020, 2019, and 2018 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)
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
2018
Cash inflows	$	29,906	$	9,866	$	9,206	$	48,978
Production costs	(13,699)		(1,799)		(2,588)		(18,086)
Development costs	(2,150)		(792)		(2,714)		(5,656)
Income tax expense	(19)		(2,455)		(1,352)		(3,826)
Net cash flows	14,038		4,820		2,552		21,410
10 percent discount rate	(6,516)		(1,066)		(107)		(7,689)
Discounted future net cash flows(2)	$	7,522	$	3,754	$	2,445	$	13,721

(1)Includes discounted future net cash flows of approximately $563 million, $1.0 billion, and $1.3 billion as of December 31, 2020, 2019, and 2018, 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 $7.1 billion, $12.4 billion, and $16.9 billion as of December 31, 2020, 2019, and 2018, respectively.

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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,
	2020		2019		2018
	(In millions)
Sales, net of production costs	$	(2,422)	$	(4,291)	$	(5,335)
Net change in prices and production costs	(5,753)		(3,034)		3,902
Discoveries and improved recovery, net of related costs	751		2,042		3,889
Change in future development costs	20		(75)		47
Previously estimated development costs incurred during the period	576		983		910
Revision of quantities	(418)		(741)		(648)
Purchases of minerals in-place	—		—		6
Accretion of discount	1,236		1,693		1,216
Change in income taxes	1,533		720		(1,125)
Sales of minerals in-place	(104)		(817)		(1)
Change in production rates and other	11		(319)		777
	$	(4,570)	$	(3,839)	$	3,638

F-66