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