apa-20231231

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, 2023


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

For the transition period from to

Commission file number 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices) (Zip Code)

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

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

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

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

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

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

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

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

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

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

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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, 2023			N/A
Number of shares of registrant’s common stock outstanding as of January 31, 2024 (100% owned by APA Corporation)			1,000

OMISSION OF CERTAIN INFORMATION

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

DOCUMENTS INCORPORATED BY REFERENCE

Portions of APA Corporation’s proxy statement relating to its 2024 annual meeting of stockholders (the APA Proxy Statement) have been incorporated by reference into Part III hereof.

TABLE OF CONTENTS


Item		Page

	PART I

1.	BUSINESS	1
1A.	RISK FACTORS	13
1B.	UNRESOLVED STAFF COMMENTS	22
1C.	CYBERSECURITY	22
2.	PROPERTIES	1
3.	LEGAL PROCEEDINGS	23
4.	MINE SAFETY DISCLOSURES	23

	PART II

5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	24
6.	SELECTED FINANCIAL DATA	24
7.	MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS	25
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	39
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	39
9A.	CONTROLS AND PROCEDURES	39
9B.	OTHER INFORMATION	39
9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	39

	PART III

10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	40
11.	EXECUTIVE COMPENSATION	40
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	40
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	40
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	40

	PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	41
16.	FORM 10-K SUMMARY	44

FORWARD-LOOKING STATEMENTS AND RISKS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included or incorporated by reference in this Annual Report on Form 10-K, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2023, 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,” “goal,” “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:

•changes in local, regional, national, and international economic conditions, including as a result of any epidemics or pandemics, such as the coronavirus disease (COVID-19) pandemic and any related variants;

•the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services, including the prices received for natural gas purchased from third parties to sell and deliver to a U.S. LNG export facility;

•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, including market and macro-economic disruptions resulting from the Russian war in Ukraine, the armed conflict in Israel and Gaza, and actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);

•the availability of capital resources;

•capital expenditures and other contractual obligations;

•currency exchange rates;

•weather conditions;

•inflation rates;

•the impact of changes in tax legislation;

•the availability of goods and services;

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

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

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

•cyberattacks and terrorism;

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

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

•the ability to retain and hire key personnel;

•property acquisitions or divestitures;

•the integration of acquisitions; 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 Narrative Analysis of Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Annual Report on Form 10-K.

Other factors or events that could cause the Company’s actual results to differ materially from the Company’s expectations may emerge from time to time, and it is not possible for the Company to predict all such factors or events. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Except as required by law, the Company disclaims any obligation to update or revise these statements, whether based on changes in internal estimates or expectations, new information, future developments, or otherwise.

DEFINITIONS

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

“3-D” means three-dimensional.

“4-D” means four-dimensional.

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

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

“bcf” means billion cubic feet of natural gas.

“bcf/d” means one bcf per day.

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

“boe/d” means boe per day.

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

“Liquids” means oil and NGLs.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or NGLs.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or NGLs.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

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

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

iii

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

iii

PART I


ITEMS 1 and 2.			BUSINESS AND PROPERTIES

GENERAL

Apache Corporation, a direct, wholly owned subsidiary of APA Corporation (APA), is an independent energy company that explores for, develops, and produces natural gas, crude oil, and NGLs. The Company’s upstream business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). Prior to the BCP Business Combination (as defined below), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

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

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

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

BUSINESS OVERVIEW

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

UPSTREAM EXPLORATION AND PRODUCTION

Operating Areas

Apache’s upstream business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea.

The following table sets out a brief comparative summary of certain key 2023 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	72.1	51	%	$	2,712	532	69	%	105	105
Egypt(1)	52.3	37	%	3,029		171	22	%	123	91
North Sea(2)	16.2	12	%	1,338		70	9	%	2	2

Total	140.6	100	%	$	7,079	773	100	%	230	198

(1)Apache’s operations in Egypt, excluding the impacts of noncontrolling interests, contributed 16 percent of 2023 production and accounted for 13 percent of year-end 2023 estimated proved reserves.

(2)Sales volumes from the Company’s North Sea assets for 2023 were 16.6 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings.

United States

In 2023, Apache’s U.S. upstream oil and gas operations contributed approximately 51 percent of production, 38 percent of oil and gas revenues, and 69 percent of estimated year-end proved reserves. Apache has access to significant liquid hydrocarbons across its 3.4 million gross acres (1.7 million net acres) in the U.S., 74 percent of which are undeveloped.

The Company’s U.S. assets are primarily located in the Permian Basin in West Texas and New Mexico, including the Permian sub-basins: Midland Basin, Central Basin Platform/Northwest Shelf, and Delaware Basin. Examples of shale plays being developed within these sub-basins include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry. Apache is one of the largest operators in the Permian Basin, operating approximately 5,000 gross oil and gas wells across its acreage, with additional interests in less than 3,000 non-operated wells. Apache also has operations located in the Eagle Ford shale and Austin Chalk areas of Southeast Texas, offshore in the Gulf of Mexico, and along the Gulf Coast in South Texas and Louisiana.

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

•Southern Midland Basin Apache holds approximately 786,000 gross acres (450,000 net acres) in the Southern Midland Basin and the Eagle Ford shale and Austin Chalk areas of southeast Texas. During 2023, the Company primarily targeted oil plays in the Wolfcamp and Spraberry formations, drilling 69 gross development wells in this basin with a 100 percent success rate.

•Delaware Basin Apache holds approximately 226,000 gross acres (129,000 net acres) in the Delaware Basin, including opportunities in the Bone Spring and other formations of Eastern New Mexico and bordering West Texas, and the Alpine High play in the southern portion of the Permian Basin, primarily in Reeves County, Texas. During 2023, the Company drilled 35 gross development wells in this basin with a 100 percent success rate.

•Legacy Assets Apache holds approximately 2.4 million gross acres (1.1 million net acres) in legacy properties, of which approximately 577,000 gross acres are in the offshore waters of the Gulf of Mexico. Consistent with the Company’s broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings provide additional monetization opportunities that continue to be evaluated.

The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its three-year capital investment program. For 2024, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserves economically.

U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. In addition, to satisfy a delivery commitment that began in 2023, the Company purchases third party natural gas to sell and deliver to a U.S. LNG export facility. 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 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), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. Apache’s objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts. These term contracts typically have a firm transportation commitment and often provide an opportunity for higher than prevailing market prices.

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

U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require Apache to deliver an average of 161 Bcf of natural gas per year for the period from 2024 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, and an average of 4.9 MMbbls of crude oil per year for the period from 2024 through 2025, in each case, at variable, domestic and/or international, market-based pricing.

Apache currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development, and/or third-party purchases. 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 2023, international assets contributed 49 percent of Apache’s production and 62 percent of its oil and gas revenues. Approximately 31 percent of estimated proved reserves at year-end 2023 were located outside the U.S.

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

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

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

Egypt Apache has decades of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt’s Western Desert. At year-end 2023, the Company held 5.3 million gross acres in six separate concessions. The Company’s acreage is primarily held under one concession agreement that resulted from the ratification of a new merged concession agreement (MCA) with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC). The MCA, which has an effective date of April 1, 2021, consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the concession. 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 67 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 Company is the contractor partner (Contractor) with EGPC and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and are reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on Apache’s Egypt operations despite impacting Apache’s production and reserves.

In conjunction with the ratification of the MCA, Apache modified partnership agreements for certain consolidated subsidiaries. The Apache subsidiary that is the sole Contractor under the MCA is owned by an Apache-operated joint venture. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a noncontrolling interest participation in the remaining two-thirds of the Company’s consolidated Egypt oil and gas business.

The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Apache’s Egypt assets, including APA and Sinopec’s noncontrolling interests, contributed 37 percent of 2023 production and 22 percent of 2023 year-end estimated proved reserves. Excluding the impacts of APA and Sinopec’s noncontrolling interests, Egypt contributed 16 percent of 2023 production and 13 percent of 2023 year-end estimated proved reserves.

In 2023, the Company drilled 75 gross development and 48 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 three million acres, which has led to recent discoveries that build and enhance the Company’s drilling inventory in Egypt. The Company will continue to focus on driving efficiencies and managing costs under the MCA.

North Sea Apache has interests in approximately 292,000 gross acres in the U.K. North Sea. These assets contributed 12 percent of Apache’s 2023 production and approximately 9 percent of year-end 2023 estimated proved reserves.

Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). In 2011, Apache acquired Mobil North Sea Limited, which included 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. During the second quarter of 2023, as part of the Company’s focus on capital allocation to optimize investment returns, it suspended all new drilling activity in the North Sea. The Company’s investment program there is now directed toward safety, base production management, and asset maintenance and integrity.

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

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

Drilling Statistics

Worldwide in 2023, Apache drilled or participated in drilling 230 gross wells, with 198 wells (86 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 during 2023, at year-end 2023, a number of wells had not yet reached completion: 69 gross (65.5 net) in the U.S., 49 gross (49.0 net) in Egypt, and 3 gross (2.5 net) in the North Sea.

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


	Net Exploratory			Net Development			Total Net Wells
	Productive	Dry	Total	Productive	Dry	Total	Productive	Dry	Total
2023
United States	—	—	—	58.1	—	58.1	58.1	—	58.1
Egypt	24.0	24.0	48.0	66.1	7.7	73.8	90.1	31.7	121.8
North Sea	1.2	—	1.2	—	—	—	1.2	—	1.2

Total	25.2	24.0	49.2	124.2	7.7	131.9	149.4	31.7	181.1
2022
United States	—	—	—	40.7	—	40.7	40.7	—	40.7
Egypt	15.0	14.5	29.5	64.4	—	64.4	79.4	14.5	93.9
North Sea	1.0	—	1.0	1.0	—	1.0	2.0	—	2.0

Total	16.0	14.5	30.5	106.1	—	106.1	122.1	14.5	136.6
2021
United States	—	—	—	67.9	—	67.9	67.9	—	67.9
Egypt	10.0	14.0	24.0	28.5	1.0	29.5	38.5	15.0	53.5
North Sea	0.6	0.5	1.1	1.8	0.5	2.3	2.4	1.0	3.4

Total	10.6	14.5	25.1	98.2	1.5	99.7	108.8	16.0	124.8

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, 2023, is set forth below:


	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	7,850	4,584	1,006	705	8,856	5,289
Egypt	1,084	1,047	108	105	1,192	1,152
North Sea	148	106	10	6	158	112
Total	9,082	5,737	1,124	816	10,206	6,553

Domestic	7,850	4,584	1,006	705	8,856	5,289
Foreign	1,232	1,153	118	111	1,350	1,264
Total	9,082	5,737	1,124	816	10,206	6,553

Gross natural gas and crude oil wells included 457 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)
2023
United States	25.8	20.8	152.9	$	10.87	$	77.80	$	20.72	$	1.81
Egypt(1)	32.5	—	118.9	9.70		82.47		—		2.91
North Sea(2)	12.7	0.4	18.3	25.34		82.75		47.77		13.02
Total	71.0	21.2	290.1	12.14		80.83		21.48		2.96
2022
United States	24.1	21.9	167.6	$	10.96	$	96.25	$	33.47	$	5.33
Egypt(1)	31.1	0.1	130.1	10.37		101.25		76.80		2.85
North Sea(2)	11.9	0.4	12.8	30.07		100.87		67.07		23.36
Total	67.1	22.4	310.5	12.75		99.39		34.62		4.97
2021
United States	27.4	24.2	192.5	$	8.37	$	67.37	$	27.85	$	3.92
Egypt(1)	25.7	0.2	96.2	11.48		70.33		48.84		2.81
North Sea(2)	13.2	0.4	14.1	26.12		69.67		54.30		12.96
Total	66.3	24.8	302.8	11.31		68.97		28.48		3.99

(1)Includes production volumes attributable to noncontrolling interests in Egypt.

(2)Sales volumes from the Company’s North Sea assets for 2023, 2022, and 2021 were 16.6 MMboe, 14.9 MMboe, and 16.1 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Gross and Net Undeveloped and Developed Acreage

The following table summarizes the Company’s gross and net acreage position by geographic area as of December 31, 2023:


	Undeveloped Acreage		Developed Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres

	(In thousands)
United States	2,524	1,148	881	541
Egypt	3,567	3,567	1,728	1,681
North Sea	133	116	159	123

Total	6,224	4,831	2,768	2,345

As of December 31, 2023, Apache held approximately 117,000 net undeveloped acres that are scheduled to expire by year-end 2024 if production is not established or the Company takes no action to extend the terms. Nearly all of the Company’s acreage expiring in 2024 is offshore the U.K. in the North Sea. The Company also held approximately 16,000 and 4,000 net undeveloped acres set to expire by year-end 2025 and 2026, respectively. Exploration concessions covering the Company’s Egyptian acreage were extended in 2021 upon ratification of the MCA with the EGPC, and no acreage is scheduled to expire before 2026. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist. The Company strives to extend the terms of many of these licenses and concession areas through operational or administrative actions but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments. No oil and gas reserves were recorded on this undeveloped acreage set to expire.

As of December 31, 2023, approximately 98 percent of U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights.

Estimated Proved Reserves and Future Net Cash Flows

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

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

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

The following table shows proved oil, NGL, and gas reserves as of December 31, 2023, based on average commodity prices in effect on the first day of each month in 2023, 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	168	146	954	472
Egypt(1)	102	—	377	165
North Sea	61	2	47	70
Total	331	148	1,378	707
Proved Undeveloped:
United States	29	16	87	60
Egypt(1)	5	—	3	6
North Sea	—	—	—	—
Total	34	16	90	66
Total Proved	365	164	1,468	773

(1)Includes total proved developed and total proved undeveloped reserves of 90 MMboe and 3 MMboe, respectively, attributable to noncontrolling interests in Egypt.

As of December 31, 2023, Apache had total estimated proved reserves of 365 MMbbls of crude oil, 164 MMbbls of NGLs, and 1.5 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 773 million boe, of which liquids represent approximately 68 percent. As of December 31, 2023, the Company’s proved developed reserves totaled 707 MMboe and estimated proved undeveloped (PUD) reserves totaled 66 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 had no fields that contained 15 percent or more of its total proved reserves for the year ended December 31, 2023. The Company had one field that contained 15 percent or more of its total proved reserves for each of the years ended December 31, 2022 and 2021.

During 2023, the Company added approximately 96 MMboe from extensions, discoveries, and other additions. The Company recorded 79 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 10 MMboe in the Delaware Basin, and 2 MMboe in the Texas Gulf Coast. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 16 MMboe of exploration and development adds, with Egypt contributing 15 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 1 MMboe from the North Sea. The Company had combined downward revisions of previously estimated reserves of 36 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, offset by engineering and performance upward revisions of 47 MMboe.

The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2023, 2022, and 2021, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 19—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 66 MMboe as of December 31, 2023, decreased by 10 MMboe from 76 MMboe of PUD reserves reported at year end 2022. During 2023, Apache converted 31 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 29 MMboe, with the remaining 2 MMboe in its international areas. The Company had no sales nor purchases in place related to PUD reserves during 2023. Apache added 65 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 44 MMboe, comprising 4 MMboe associated with engineering and interest revisions, 12 MMboe associated with revised development plans, and 28 MMboe associated with product prices.

During 2023, a total of approximately $318 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 2023, Apache spent approximately $264 million on PUD reserve development activity in the U.S. and $54 million in the international areas. As of December 31, 2023, Apache had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.

Preparation of Oil and Gas Reserve Information

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

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

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

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year, and reserves volume. During 2023, the properties selected for all countries represented 88 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 91 percent of the value of Apache’s international proved reserves and 95 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 83 percent of total proved reserves on a boe basis.

The percentages of total estimated proved reserves values, calculated as future net cash flows discounted at 10 percent, and volumes, on a boe basis, covered by Ryder Scott’s reviews for the years 2023, 2022, and 2021 were:


	2023		2022		2021
Estimated proved reserves values	88	%	82	%	83	%

Estimated proved reserves volumes:
United States	82	%	80	%	80	%
Egypt	80	%	80	%	80	%
North Sea	90	%	81	%	81	%
Apache Worldwide	83	%	80	%	80	%

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 Midstream LLC, one of Apache’s wholly owned subsidiaries, completed a transaction with ALTM and its then wholly owned subsidiary Altus Midstream LP to create a pure-play, Permian Basin midstream C-corporation anchored by gathering, processing, and transmission assets at Alpine High. Pursuant to the agreement, Apache’s subsidiary contributed certain Alpine High midstream assets and options to acquire equity interests in five separate third-party pipeline projects to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, Apache’s subsidiary received economic voting and non-economic voting shares in ALTM and limited partner interests in Altus Midstream LP, representing an approximate 79 percent ownership interest in the combined entities. As a result, Apache fully consolidated the assets and liabilities of ALTM in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.

Business Combination with BCP

On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination created an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. Pursuant to the BCP Contribution Agreement, Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination).

As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction closed during the first quarter of 2022. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc.

After the transaction closed, Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock. Upon closing the transaction, the Company no longer consolidated the assets and liabilities of ALTM in its consolidated financial statements. Subsequent to the close of the transaction, in March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock (Kinetik Shares) for $224 million, reducing the Company’s ownership in Kinetik to approximately 13 percent.

In December 2023, the Company sold an additional 7.5 million of its Kinetik Shares for cash proceeds of $228 million. As of December 31, 2023, the Company owned 13.1 million Kinetik Shares, representing approximately 9 percent of Kinetik’s outstanding common stock.

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 each of 2023 and 2022, sales to EGPC accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs 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.

OFFICES

The Company’s principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. As of year-end 2023, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache’s primary office space is leased. The current lease on the Company’s principal executive offices runs through December 31, 2024. The Company plans to move its principal executive offices in 2024 to One Briarlake Plaza in Houston, Texas, under an existing lease that expires on December 31, 2038, subject to the lessee’s option to extend the term by up to 20 years. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

TITLE TO INTERESTS

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

ADDITIONAL INFORMATION ABOUT THE COMPANY

Response Plans and Available Resources

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

Apache is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any affiliated entity worldwide to access OSRL’s services. OSRL maintains aircraft available for global dispersant application and has a number of active recovery boom systems that can be used for offshore, nearshore, or shoreline responses. In addition to the services and equipment provided to all members of OSRL, the Company maintains membership to supplementary services from OSRL, including the U.K. Continental Shelf (UKCS) Aerial Surveillance, OSPRAG Capping Stack, and Dispersant Stockpile, providing equipment and services specifically tailored for an emergency response in the North Sea.

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. CGA equipment includes skimming vessels, barges, boom, and dispersants.

Additionally, the Company has contracted with Wild Well Control Company for contingency planning for and response to uncontrolled subsea well events and other drilling activities. The Company utilizes a detailed Emergency Response Plan (ERP) for offshore response preparedness. The ERP has been designed to ensure that the goals of the Company’s 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 industry is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and the gathering and marketing of oil, gas, and NGLs. The Company’s competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.

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

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

Environmental Compliance

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

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


ITEM 1A.			RISK FACTORS

The Company’s business activities and the value of APA’s securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA’s securities could lose part or all of their investments. Additional risks and uncertainties not presently known to the Company or that the Company currently considers immaterial may also adversely affect the Company.

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

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

The Company’s revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products. 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 2023 ranged from a high of $93.67 per barrel to a low of $66.61 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2023 ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company’s control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:

•worldwide and domestic supplies and/or inventories of crude oil, natural gas, and NGLs and the availability of related pipeline, transportation, import/export, and refining capacity and infrastructure;

•actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);

•political conditions and events in oil and gas producing regions, including instabilities, changes in governments, or armed conflicts, such as the Russian war in Ukraine and the armed conflict in Israel and Gaza;

•the price, competitiveness, decision to use, and availability of alternative fuels and energy sources, including coal, biofuels, and renewables;

•increased competitiveness of, and demand for, alternative energy sources;

•technological advances affecting energy supply and energy consumption, including those that alter fuel choices;

•the availability of pipeline capacity and infrastructure;

•the availability of crude oil transportation and refining capacity;

•weather conditions;

•the impact of political pressure and the influence of environmental groups, investors, and other stakeholders on decisions and policies related to the oil and gas industry, including with respect to environmental, social, and governance matters;

•domestic and foreign governmental regulations and taxes, including changes or initiatives to address the impacts of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and

•the overall economic environment, including rates of growth and increasing inflationary pressure.

Low prices have previously adversely affected and could from time to time in the future adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and a prolonged period of low prices could have a material adverse impact on the Company’s results of operations and cash flows and limit its ability to fund capital expenditures. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs could also further adversely impact the Company’s business, including by weakening the Company’s financial condition and reducing its liquidity, limiting the Company’s ability to fund planned capital expenditures and operations, causing the Company to delay or postpone some of its capital projects or reallocate capital to different projects or regions, limiting the Company’s access to sources of capital, such as equity and long-term debt, or reducing the carrying value of the Company’s oil and gas properties, resulting in additional non-cash impairments.

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

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

The Company has previously not realized, and may in the future not realize, an adequate return on wells that it drills.

Drilling for oil and gas involves numerous risks, including that the Company may not encounter commercially productive oil or gas reservoirs or may not recover all or any portion of its investment in the wells it drills. Management has previously determined, and may in the future determine, that future drilling or development activities will not, or are unlikely to, occur for a well or reservoir, based on drilling results, current or future estimated commodity prices or demand for oil, natural gas, and NGLs, or other information. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations are subject to a variety of risks, including unexpected drilling conditions (such as pressure or formation irregularities), equipment failures or accidents, catastrophic events, marine risks, adverse weather conditions, and increases in the cost of or shortages or delays in the availability of drilling rigs, equipment, and labor. In addition, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Any such events could have an adverse effect on the Company’s future results of operations and financial condition. Exploration costs and dry hole expenses incurred by the Company during the reporting period are further discussed in this Annual Report on Form 10-K and reflected in the consolidated financial statements included herein.

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

To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases. The Company’s hedging arrangements may expose it to the risk of financial loss, including when production falls short of the hedged volumes, price-basis differentials widen, a hedging counterparty defaults, or an unexpected event materially impacts commodity prices.

Global pandemics have previously, may continue to, and may in the future adversely impact the Company’s business, financial condition, and results of operations; the global economy; the demand for and prices of oil, natural gas, and NGLs; and the performance of the Company’s workforce.

Global pandemics and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to such pandemics, including the COVID-19 pandemic, have previously adversely impacted and may from time to time in the future adversely impact the global economy, resulting in significant volatility in the global financial markets, and the demand for, and the prices of, oil, natural gas, and NGLs, which may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations. Additionally, the Company’s operations rely on its workforce having access to its wells, platforms, structures, offices, and facilities. If a significant portion of the Company’s workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions (including vaccine mandates and the reactions thereto), or other restrictions or adverse impacts resulting from a pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.

RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS

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

The Company’s operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including well blowouts, explosions, fires, cratering, pipeline or other facility ruptures and spills, adverse weather conditions, including those impacting the Company’s offshore operating areas, surface spillage and

ground water contamination, and failure or loss of equipment. These events, including ineffective containment of such events, could result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. If a significant amount of the Company’s production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company’s cash flows and, in turn, its results of operations could be materially and adversely affected.

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

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

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

Exploration for and production of crude oil, natural gas, and NGLs involves hazards, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company’s international operations are also subject to political and economic risks. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks. While certain of the Company’s insurance policies may provide coverage for such events, if the Company were to incur a significant liability for which it was not fully insured, then it could have a material adverse effect on the Company’s financial position, results of operations, and cash flows. In addition, if such an event were to occur, then the proceeds of any such insurance may not be paid in a timely manner or may not be sufficient to cover all of the Company’s losses.

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

There are numerous and evolving risks to the Company’s data, technology, and information systems from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage, and employee malfeasance. The Company’s operations are dependent on digital technologies, including to estimate reserves, process financial and operating data, analyze drilling information, and communicate with personnel. Unauthorized access to the Company’s data, technology, and information systems could lead to operational disruption, communication interruption, disruption in access to financial reporting systems, loss, misuse, or corruption of data and proprietary information. In addition, unauthorized access to third party information systems could interrupt the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company’s production. Cyberattacks directed at oil and gas distribution systems have previously and could again in the future damage critical distribution and storage assets or the environment. The potential impacts of a cyber incident could be made worse by a delay or failure to detect the occurrence, continuance, or extent of such an incident.

The Company expends significant resources to protect its digital systems and data, whether such data is housed internally or externally by third parties, against cyberattacks and may be required to expend further resources as cyber threat actors become more sophisticated and as regulations related to cyberattacks become more complex. Cyberattacks, including malicious software, data privacy breaches by employees, insiders, or others with authorized access to the Company’s systems, cyber or phishing attacks, ransomware attacks, supply chain vulnerabilities, business email compromises, other attempts to gain unauthorized access to the Company’s data and systems, and other electronic security breaches could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation. While the Company has not suffered any material losses as a result of cyberattacks, there is no assurance that the Company will not suffer such losses in the future.

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

The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by project approvals from joint venture

partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events and development costs (including for equipment and personnel) may adversely affect the Company’s large development projects (including forcing the Company to abandon such projects) and its ability to participate in large-scale development projects in the future.

RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE

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

The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, future oil and gas production is highly dependent upon the Company’s level of success in adding reserves through exploration and development activities, identifying additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquiring additional properties containing proved reserves. As oil or natural gas prices increase, the Company’s cost for additional reserves could also increase.

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

Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. 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. There can be no assurance that acquisitions will not adversely impact the Company’s operating results, particularly during their integration into the Company’s ongoing operations.

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

There are numerous uncertainties inherent in the process of estimating crude oil, natural gas, and NGL reserves and their value, which is highly subjective and relies on the quality of available data and the accuracy of engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist, causing reserves quantities to change when actual prices increase or decrease. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including historical production from the area compared with production from other areas, the results of drilling, testing, and production for a reservoir over time, the use of volumetric analysis versus production history, the effects of changes in laws (including taxes), future operating, workover, and remediation costs, and capital expenditures. Accordingly, reserves estimates may be subject to adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

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

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

RISKS RELATED TO COUNTERPARTIES

The credit risk of financial institutions could adversely affect the Company and result in a significant loss.

The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions, including in the form of derivative transactions in connection with any hedges and claims under the Company’s insurance policies, which expose the

Company to credit risk in the event of default of the counterparty. Deterioration or volatility in the credit or financial markets, changes in commodity prices, and changes in a counterparty’s liquidity may affect the counterparties’ ability to fulfill their existing obligations to the Company. In addition, if any lender under the Company’s credit facilities is unable to fund its commitment, the Company’s liquidity may be reduced by an amount up to the aggregate amount of such lender’s commitment thereunder. Furthermore, the bankruptcy of one or more of the Company’s counterparties or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities, and the Company could incur a significant loss.

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

The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. As a result of previous severe declines in commodity prices, some of the Company’s customers and non-operating partners experienced severe financial problems. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company (including as a result of their filing for bankruptcy or other liquidity constraints) or that such a default or defaults will not have a material adverse effect on the Company’s business, financial position, future results of operations, or future cash flows.

The Company’s liabilities, including for the decommissioning of previously owned assets, could be adversely affected in the event one or more of its transaction counterparties are financially distressed or become the subject of a bankruptcy case.

The agreements relating to the Company’s divestment of domestic and international assets generally contain provisions pursuant to which liabilities related to past and future operations (one of the most significant of which is the decommissioning of wells and facilities) are allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, bonds, letters of credit, and similar arrangements. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress or bankruptcy, which may force the Company to use available cash to cover the costs of such obligations, pending final resolution of any claims the Company may have against the counterparty, which could adversely impact the Company’s cash flows, operations, or financial condition.

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

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

The Company conducts many of its exploration and production (E&P) operations through joint operating agreements or joint ventures with other parties. The Company may not control decisions made under such agreements or ventures, either because it does not have a controlling interest in the venture or is not an operator under the agreement. The other parties to these arrangements may have economic, business, or legal interests or goals that are inconsistent with the Company’s, and, therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to such agreements or ventures may be unable to meet their economic or other obligations, and the Company may be required to fulfill those obligations alone. In either case, the value of the investment and the Company’s business and financial condition may be adversely affected.

RISKS RELATED TO CAPITAL MARKETS

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

The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company’s credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company’s ability to access debt markets in the future and increase the cost of future debt. During 2023, Moody’s upgraded the Company’s rating to Baa3/Stable, and Standard and Poor’s affirmed the Company’s rating as BB+/Positive. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.

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

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

APA Corporation’s syndicated revolving credit facilities currently mature in April 2027. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to APA, the Company, or APA’s other subsidiaries or the composition of such lenders.

Actions by advocacy groups to advance climate change and energy transition initiatives, unfavorable ESG ratings, and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from companies in the oil and gas industry, which could negatively impact the Company’s access to and costs of capital or the market for APA’s securities.

Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Unfavorable ESG ratings may lead to negative investor and public sentiment toward the Company, which may cause the market for APA’s securities to be negatively impacted.

In addition, a number of advocacy groups have campaigned for governmental and private action to influence change in the business strategies of oil and gas companies, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These campaign efforts have resulted in the divestment of investments in the oil and gas industry and increased pressure on lenders and other financial services companies to limit or curtail activities with oil and gas companies. If investors or financial institutions shift funding away from companies in the oil and gas industry, the Company’s access to and costs of capital or the market for APA’s securities may be negatively impacted.

RISKS RELATED TO FINANCIAL RESULTS

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

Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes for leases, equipment, labor, key personnel, and marketing of crude oil, natural gas, and NGL production, the prices of which impact the costs of properties and the financial resources available to pursue acquisitions. These competitive pressures may have a significant negative impact on the Company’s results of operations.

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

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

RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS

The Company may incur significant costs related to environmental matters.

As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or

constrain operations in affected areas, require significant capital expenditures to comply with increasingly strict environmental laws and regulations, and require suspension or cessation of operations in affected areas. The Company’s efforts to limit its exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company’s results of operations and cash flows.

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

The Company’s U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations, including restrictions on production, changes in taxes and other amounts payable to governments, price or gathering rate controls, environmental protection laws and regulations, and security for plugging, abandonment, and decommissioning obligations, including in the Gulf of Mexico.

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

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

The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for oil and natural gas to migrate toward the wellbore, typically at substantial depths in formations with low permeability. Governmental entities have previously taken actions to regulate, and several proposals are before the U.S. Congress that, if implemented, would further regulate, hydraulic fracturing. If adopted, such regulations could impose more stringent permitting, reporting, and well construction requirements or otherwise seek to ban fracturing activities. These activities and the associated water disposal activities are under scrutiny due to their potential environmental and physical impacts, including possible water contamination and possible links to induced seismicity. Any new federal, state, or local restrictions on hydraulic fracturing could result in increased compliance costs or additional restrictions on the Company’s U.S. operations.

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

Federal, state, and foreign income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. For example, the U.K. enacted the Energy Profits Levy, which assesses an additional levy of 35 percent, effective for the period of January 1, 2023, through March 31, 2028, on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Additionally, in the U.S., the Inflation Reduction Act of 2022 introduced a new 15 percent corporate alternative minimum tax (Corporate AMT) for taxable years beginning after December 31, 2022, on applicable corporations with an average annual adjusted financial statement income (AFSI) that exceeds $1.0 billion for any three consecutive tax years preceding the tax year at issue. Effective January 1, 2024, the Company is subject to the Corporate AMT. Accordingly, any resulting Corporate AMT liability could adversely affect the Company’s future financial results, including earnings and cash flows.

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

RISKS RELATED TO CLIMATE CHANGE

The impacts of energy transition could adversely affect the Company’s business, operating results, and financial condition.

In recent years, increasing attention has been given to corporate activities related to climate change and energy transition. This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power, and the

development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more energy-efficient products and services.

These developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for, and in turn the prices the Company receives for, its crude oil, natural gas, and NGL products, which could materially and adversely affect the Company’s business and financial performance.

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

Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company’s operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company’s cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions. Moreover, in January 2024, the EPA announced a proposed rule to assess a charge on certain methane emissions in the oil and gas industry. The Company is currently evaluating the proposed rule and its applicability to the Company.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts.

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

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

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

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

Given the dynamic nature of the Company’s business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company’s internally prepared base-case pricing analysis averaged out to the year 2040. Given the numerous estimates that are required to run these scenarios, the Company’s estimates could differ materially from actual results. The Company publicly discloses these metrics and its related assumptions and analysis in its annual sustainability report. By electing to disclose these metrics, the Company may face increased scrutiny related to its ESG initiatives. Any harm to the Company’s reputation resulting from publicly disclosing such these metrics, expanding disclosures related to such metrics, or failing to achieve such metrics or abiding by such disclosures could adversely affect the Company’s business, financial performance, and growth.

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

In 2022, the Company modified the way it reports its water data compared to previous years and restated its data from prior years. Previously, the Company included produced water usage in its consumptive use calculations, which led to an over-reporting of consumptive water use. Based on re-evaluation of water reporting definitions and guidance, the Company determined that produced water (non-potable water released from deep underground formations and brought to the surface during oil and gas exploration and production) should not be classified as consumed in the same sense as fresh water. The

Company’s revised reporting now reflects only fresh water and non-potable water from surface water or shallow groundwater that are consumed in oil and gas operations.

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

The treatment and disposal of produced water is becoming more highly regulated and restricted. Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection) and to require the monitoring of seismic activity. While the Company remains focused on reusing or recycling water over disposal of water, the Company’s costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water and restrictions related to disposal wells may increase the Company’s operating costs or capital expenses or cause the Company to limit production, which could materially and adversely affect its business, results of operations, and financial conditions.

RISKS RELATED TO INTERNATIONAL OPERATIONS

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

The Company’s operations outside the U.S. are based in Egypt and the U.K. On a barrel equivalent basis, approximately 49 percent of the Company’s 2023 production was outside the U.S., and approximately 31 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2023, were located outside the U.S. As a result, a significant portion of the Company’s production and resources are subject to the increased political and economic risks and other factors associated with international operations, including, but not limited to strikes and civil unrest; war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts; import and export regulations; taxation policies and investment restrictions; price controls; exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds; constrained oil or natural gas markets dependent on demand in a single or limited geographical area; laws and policies of the U.S. affecting foreign trade, including trade sanctions; the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates; the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and difficulties in enforcing the Company’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

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

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

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

Further deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company’s assets or resource nationalization, and/or forced renegotiation or modification of the Company’s existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company’s business

and operations. Additionally, deteriorating economic conditions in Egypt have led to a shortage of foreign currency, including U.S. dollars, resulting in a decline in the timeliness of payments from EGPC. A continuation or worsening of the currency shortage in Egypt or further deterioration of economic conditions there could lead to additional payment delays, deferrals of payment, or non-payment in the future. The Company’s operations in Egypt, excluding the impacts of noncontrolling interests, contributed 16 percent of the Company’s 2023 production and accounted for 13 percent of the Company’s year-end estimated proved reserves and 25 percent of the Company’s estimated discounted future net cash flows. If conditions continue to deteriorate in Egypt, then it could materially and adversely affect the Company’s business, financial condition, and results of operations.

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

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


ITEM 1B.			UNRESOLVED STAFF COMMENTS

Not applicable.


ITEM 1C.			CYBERSECURITY

Risk Management and Strategy

As a wholly owned subsidiary of APA, the Company relies on APA for its information systems in connection with the Company’s day-to-day operations. Consequently, the Company also relies on the processes undertaken by APA for assessing, identifying, and managing material risks from cybersecurity threats. The Company’s executive officers are executive officers of APA, and one of such officers (John J. Christmann IV) is also a member of APA’s board of directors (the APA Board of Directors).

APA maintains a cybersecurity program that establishes safeguards for protecting the confidentiality, integrity, and availability of APA’s data, technology, and information systems, and the material risks associated with the threats identified from time to time under the cybersecurity program are incorporated into APA’s corporate risk register. The program includes general controls for managing changes in and access to APA’s information technology environment, cybersecurity awareness and training programs to help employees identify and mitigate against cybersecurity threats, cybersecurity incident response plans and third-party incident response retainers to help expedite APA’s response in the event of a cybersecurity incident, and guidelines regarding system vulnerability management, third-party threat intelligence, endpoint detection and response solutions, and network security measures.

APA’s Chief Information Officer (the CIO) is primarily responsible for the day-to-day operation of APA’s cybersecurity program and for identifying, assessing, and managing the material risks associated with the cybersecurity threats and incidents identified from time to time thereunder.

In 2023, the APA Board of Directors established a standing Cybersecurity Committee to assist with oversight of APA’s cybersecurity program and the material risks associated with the threats identified under the program. The Cybersecurity Committee receives regular reports from APA management, including the CIO, regarding APA’s cybersecurity systems and programs, and the committee from time to time also receives updates from external cybersecurity specialists on cybersecurity trends and incidents.

As of December 31, 2023, no risks from cybersecurity threats or incidents have materially affected or are reasonably likely to materially affect the Company’s business strategy, results of operations, or financial condition.

For additional information regarding relevant cybersecurity risks, see Item 1A―Risk Factors ― “A cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company’s operations.”


ITEM 3.			LEGAL PROCEEDINGS

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


ITEM 4.			MINE SAFETY DISCLOSURES

Not applicable.

PART II


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

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


ITEM 6.			SELECTED FINANCIAL DATA

Omitted.


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

The following discussion relates to Apache Corporation (Apache or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Narrative Analysis of Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 (filed with the SEC on February 23, 2023).

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

Overview

Apache, a direct, wholly owned subsidiary of APA, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

Apache believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. Apache strives to meet those challenges while creating value for all its stakeholders.

Uncertainties in the global supply chain and financial markets, including the impact of inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to invest for long-term returns in pursuit of sustainable production; (2) to strengthen the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction and return of capital to APA; and (3) to responsibly manage its cost structure regardless of the oil price environment.

Financial and Operational Highlights

During 2023, the Company reported net income of $2.5 billion compared to net income of $3.5 billion in 2022. Net income in 2023 was primarily impacted by lower revenues attributable to significantly lower realized commodity prices compared to 2022. The lower revenues were partially offset by a release of a majority of the Company’s U.S. tax valuation allowance, resulting in a non-cash deferred income tax benefit of approximately $1.7 billion during the fourth quarter of 2023. Net income in 2022 also benefited from approximately $1.2 billion of gains from the divestiture of certain non-core mineral rights in the Delaware Basin and completion of the BCP Business Combination.

The Company generated $2.9 billion of cash from operating activities in 2023, which was $1.9 billion, or 40 percent, lower than 2022. Apache’s lower operating cash flows for 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items.

Key operational highlights for the year include:

United States

•Daily boe production from the Company’s U.S. assets, which decreased 3 percent from 2022, accounted for 51 percent of the Company’s worldwide production during 2023. The Company averaged three drilling rigs in the U.S. during the year in the Southern Midland Basin and brought online 60 operated wells in 2023. The Company’s drilling was primarily focused on oil prospects, increasing oil production by approximately 7 percent in the U.S. compared to the prior year. The Company’s core Permian Basin development program continues to represent a key growth area for the U.S. assets.

International

•In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 17 drilling rigs and drilled 91 new productive wells during 2023. During 2023, gross and net production from the Company’s Egypt assets decreased 2 percent and 1 percent, respectively, from 2022. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage opportunities provided by the 2021 merged concession agreement.

•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program in the North Sea is now directed toward safety, base production management, and asset maintenance and integrity.

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

•BCP Business Combination On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik). The Company deconsolidated ALTM upon closing the transaction. The deconsolidation provides a number of benefits to the Company’s shareholders, including simplification of the Company’s financial reporting and enhanced comparability with its upstream-only peers, while maintaining a noncontrolling interest in future growth opportunities of Kinetik.

•Delaware Basin Divestitures During 2022, the Company completed a previously announced transaction to sell certain non-core mineral rights in the Delaware Basin, for total cash proceeds of $726 million.

•Sales of Kinetik Shares Subsequent sales of Kinetik Shares have reduced APA’s ownership in Kinetik to approximately 9 percent as of December 31, 2023. During 2023, the Company sold a portion of its Kinetik Shares for cash proceeds of $228 million. During 2022, the Company sold a portion of its Kinetik Shares for $224 million.

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

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

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


	For the Year Ended December 31,
	2023				2022				2021
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution

	($ in millions)
Oil Revenues:
United States	$	2,003	35	%	$	2,323	35	%	$	1,850	40	%
Egypt(1)	2,683		46	%	3,145		47	%	1,806		40	%
North Sea	1,073		19	%	1,232		18	%	929		20	%
Total(1)	$	5,759	100	%	$	6,700	100	%	$	4,585	100	%

Natural Gas Revenues:
United States	$	277	32	%	$	894	58	%	$	754	62	%
Egypt(1)	346		40	%	370		24	%	270		23	%
North Sea	237		28	%	281		18	%	183		15	%
Total(1)	$	860	100	%	$	1,545	100	%	$	1,207	100	%

NGL Revenues:
United States	$	432	94	%	$	732	93	%	$	673	95	%
Egypt(1)	—		—	%	6		1	%	9		1	%
North Sea	28		6	%	45		6	%	24		4	%
Total(1)	$	460	100	%	$	783	100	%	$	706	100	%

Oil and Gas Revenues:
United States	$	2,712	38	%	$	3,949	44	%	$	3,277	50	%
Egypt(1)	3,029		43	%	3,521		39	%	2,085		32	%
North Sea	1,338		19	%	1,558		17	%	1,136		18	%
Total(1)	$	7,079	100	%	$	9,028	100	%	$	6,498	100	%

(1)Includes revenues attributable to noncontrolling interests in Egypt.

Production

The following table presents production volumes by country:


	For the Year Ended December 31,
	2023	Increase (Decrease)	2022	Increase (Decrease)	2021
Oil Volumes – b/d:
United States(5)	70,562	7%	66,142	(12)%	75,205
Egypt(3)(4)	89,129	5%	85,081	21%	70,349
North Sea	34,728	7%	32,578	(10)%	36,265
Total	194,419	6%	183,801	1%	181,819

Natural Gas Volumes – Mcf/d:
United States(5)	418,972	(9)%	459,123	(13)%	527,461
Egypt(3)(4)	325,778	(9)%	356,327	35%	263,653
North Sea	50,284	42%	35,327	(8)%	38,565
Total	795,034	(7)%	850,777	3%	829,679

NGL Volumes – b/d:
United States(5)	57,035	(5)%	59,887	(10)%	66,232
Egypt(3)(4)	—	NM	196	(63)%	531
North Sea	1,240	12%	1,111	(7)%	1,199
Total	58,275	(5)%	61,194	(10)%	67,962

BOE per day:(1)
United States(5)	197,426	(3)%	202,549	(12)%	229,348
Egypt(3)(4)	143,425	(1)%	144,665	26%	114,821
North Sea(2)	44,349	12%	39,577	(10)%	43,892
Total	385,200	—%	386,791	—%	388,061

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

(2)Average sales volumes from the North Sea were 45,476 boe/d, 40,812 boe/d, and 44,179 boe/d for 2023, 2022, and 2021, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

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


	2023	2022	2021
Oil (b/d)	141,985	137,260	134,711
Natural Gas (Mcf/d)	500,080	555,562	586,663
NGL (b/d)	—	297	854

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


	2023	2022	2021
Oil (b/d)	59,449	45,216	23,504
Natural Gas (Mcf/d)	217,296	189,339	88,409
NGL (b/d)	—	104	177

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


	2023	2022	2021
Oil (b/d)	573	777	1,485
Natural Gas (Mcf/d)	174,454	192,253	258,096
NGL (b/d)	16,482	18,362	22,950

NM — Not Meaningful

Pricing

The following table presents pricing information by country:


	For the Year Ended December 31,
	2023		Increase (Decrease)	2022		Increase (Decrease)	2021
Average Oil Price - Per barrel:
United States	$	77.80	(19)%	$	96.25	43%	$	67.37
Egypt	82.47		(19)%	101.25		44%	70.33
North Sea	82.75		(18)%	100.87		45%	69.67
Total	80.83		(19)%	99.39		44%	68.97

Average Natural Gas Price - Per Mcf:
United States	$	1.81	(66)%	$	5.33	36%	$	3.92
Egypt	2.91		2%	2.85		1%	2.81
North Sea	13.02		(44)%	23.36		80%	12.96
Total	2.96		(40)%	4.97		25%	3.99

Average NGL Price - Per barrel:
United States	$	20.72	(38)%	$	33.47	20%	$	27.85
Egypt	—		NM	76.80		57%	48.84
North Sea	47.77		(29)%	67.07		24%	54.30
Total	21.48		(38)%	34.62		22%	28.48

NM — Not Meaningful

Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2023 were down 19 percent compared to 2022, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2023 averaged $80.83 per barrel.

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

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

•The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $1.81 per Mcf in 2023, a 66 percent decrease from an average of $5.33 per Mcf in 2022.

•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.91 per Mcf in 2023, a 2 percent increase from an average of $2.85 per Mcf in 2022.

•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $13.02 per Mcf in 2023, a 44 percent decrease from an average of $23.36 per Mcf in 2022.

NGL Prices The Company’s U.S. NGL production, which accounted for 98 percent of the Company’s total 2023 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Crude Oil Revenues

Crude oil revenues for 2023 totaled $5.8 billion, a $941 million decrease from the 2022 total of $6.7 billion. A 19 percent decrease in average realized prices reduced 2023 revenues by $1.3 billion compared to 2022, while 6 percent higher average daily production increased revenues by $311 million. Average daily production in 2023 was 194 Mb/d, with prices averaging $80.83 per barrel. Crude oil sales accounted for 81 percent of the Company’s 2023 oil and gas production revenues and 50 percent of its worldwide production.

The Company’s worldwide crude oil production increased 11 Mb/d compared to 2022, primarily a result of increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.

Natural Gas Revenues

Natural gas revenues for 2023 totaled $860 million, a $685 million decrease from the 2022 total of $1.5 billion. A 40 percent decrease in average realized prices reduced 2023 revenues by $627 million compared to 2022, while 7 percent lower average daily production decreased revenues by $58 million. Average daily production in 2023 was 795 MMcf/d, with prices averaging $2.96 per Mcf. Natural gas sales accounted for 12 percent of the Company’s 2023 oil and gas production revenues and 34 percent of its worldwide production.

The Company’s worldwide natural gas production decreased 56 MMcf/d compared to 2022, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., partially offset by increased drilling activity and recompletions and less maintenance downtime in the North Sea.

NGL Revenues

NGL revenues for 2023 totaled $460 million, a $323 million decrease from the 2022 total of $783 million. A 38 percent decrease in average realized prices reduced 2023 revenues by $297 million compared to 2022, while 5 percent lower average daily production decreased revenues by $26 million. Average daily production in 2023 was 58 Mb/d, with prices averaging $21.48 per barrel. NGL sales accounted for 7 percent of the Company’s 2023 oil and gas production revenues and 16 percent of its worldwide production.

The Company’s worldwide NGL production decreased 3 Mb/d compared to 2022, primarily a result of natural production decline across all assets, partially offset by increased drilling activity and recompletions and less maintenance downtime in the North Sea.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations and delivery commitments. In 2023, in order to diversify the pricing received for the sale of its natural gas, the Company sold a portion of its purchased gas at international gas prices. Sales related to purchased volumes decreased $961 million for the year ended December 31, 2023 to $894 million from $1.9 billion in 2022. Purchased oil and gas sales were partially offset by associated purchase costs of $742 million and $1.8 billion for the years ended December 31, 2023 and 2022, respectively. The decrease in purchased oil and gas sales is primarily a result of lower average domestic natural gas prices during 2023 compared to 2022.

Operating Expenses

The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2023, 2022, and 2021. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Lease operating expenses	$	1,397	$	1,435	$	1,241
Gathering, processing, and transmission	314		356		264
Purchased oil and gas costs	742		1,776		1,580
Taxes other than income	192		256		204
Exploration	153		146		127
General and administrative	325		462		357
Transaction, reorganization, and separation	15		26		22
Depreciation, depletion, and amortization:
Oil and gas property and equipment	1,359		1,130		1,255
Gathering, processing, and transmission assets	6		15		64
Other assets	34		32		41
Asset retirement obligation accretion	116		117		113
Impairments	61		—		208
Financing costs, net	165		313		472

Lease Operating Expenses (LOE)

LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 50 percent of the Company’s total 2023 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2023, LOE decreased $38 million, or 3 percent, compared to 2022. On a per-boe basis, LOE remained essentially flat compared to 2022. The decrease in absolute costs was driven by lower average foreign currency exchange impacts against the U.S. dollar and decreased workover activity primarily in the North Sea. These decreases were mostly offset by higher labor costs and other operating costs trending with general inflation across all regions.

Gathering, Processing, and Transmission (GPT)

GPT expenses include amounts paid to third-party carriers for gathering and transmission services for the Company’s upstream natural gas production. Prior to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, GPT expenses also included gathering and transmission services provided by Altus Midstream and midstream operating costs incurred by Altus. The following table presents a summary of these expenses:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Third-party processing and transmission costs	$	214	$	260	$	232
Midstream service costs – ALTM	—		18		128
Midstream service costs – Kinetik	100		91		—
Upstream processing and transmission costs	314		369		360
Midstream operating expenses	—		5		32
Intersegment eliminations	—		(18)		(128)
Total Gathering, processing, and transmission	$	314	$	356	$	264

GPT costs decreased $42 million compared to 2022, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $55 million from 2022, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the Company’s deconsolidation of Altus in February 2022, these midstream services continue to be provided by Kinetik but are no longer eliminated.

Purchased Oil and Gas Costs

Purchased oil and gas costs decreased $1.0 billion for the year ended December 31, 2023, to $742 million from $1.8 billion in 2022. The decrease is a result of lower average domestic natural gas prices during 2023 compared to the prior year. Purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $894 million for the year ended 2023, as discussed above.

Taxes Other Than Income

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

Taxes other than income decreased $64 million compared to 2022, primarily from lower severance taxes driven by lower commodity prices and lower ad valorem tax rates.

Exploration Expenses

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Unproved leasehold impairments	$	21	$	24	$	31
Dry hole expenses	87		69		55
Geological and geophysical expenses	3		6		8
Exploration overhead and other	42		47		33
Total Exploration	$	153	$	146	$	127

Exploration expenses increased $7 million compared to 2022, primarily the result of higher dry hole expense from increased Egypt exploration activity during 2023.

General and Administrative (G&A) Expenses

G&A expenses decreased $137 million compared to 2022, primarily driven by lower cash-based stock compensation expense during 2023 resulting from decreases in the Company’s stock price and in the achievement of performance and financial objectives as defined in the stock award plans. For additional information refer to Note 15—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $11 million compared to 2022. Higher TRS costs in 2022 were incurred in connection with the BCP Business Combination in the first quarter of 2022.

Depreciation, Depletion and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2023 increased $229 million compared to 2022. The Company’s oil and gas property DD&A rate increased $1.85 per boe in 2023 compared to 2022, from $7.79 per boe to $9.64 per boe, driven by general cost inflation and the unit of production impact of lower proved reserves during 2023. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and acquisitions in the U.S.

Impairments

During 2023, the Company recorded $61 million of impairments, primarily in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. No asset impairments were recorded in 2022.

Financing Costs, Net

Financing costs incurred during 2023, 2022, and 2021 comprised the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Interest expense	$	291	$	312	$	419
Amortization of debt issuance costs	2		7		8
Capitalized interest	—		(1)		—
Loss (gain) on extinguishment of debt	(9)		67		104
Interest income	(10)		(9)		(8)
Interest income from APA Corporation, net	(109)		(63)		(51)
Total Financing costs, net	$	165	$	313	$	472

Net financing costs during 2023 decreased $148 million compared to 2022, primarily driven by losses incurred on the extinguishment of debt during 2022, gains on extinguishment of debt during 2023, and higher intercompany interest income from APA Corporation in 2023.

Provision for Income Taxes

Income tax expense decreased $2.0 billion from $1.7 billion during 2022 to an income tax benefit of $314 million during 2023. The Company’s 2023 effective income tax rate was primarily impacted by a deferred tax expense related to the release of a portion of its valuation allowance against U.S. deferred tax assets and the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023. During 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.

On July 14, 2022, the Energy Profits Levy was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under accounting principles generally accepted in the U.S., the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded a deferred tax expense of $208 million and $174 million related to the remeasurement of the U.K. deferred tax liability in 2022 and 2023, respectively.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company is not an applicable corporation in 2023 but will be subject to CAMT beginning on January 1, 2024. The Company is continuing to evaluate the provisions of the IRA and its effects on the Company’s consolidated financial statements.

In December 2021, the Organisation for Economic Co-operation and Development (OECD) released Model Rules under the Pillar Two framework, which imposes a 15 percent global minimum tax on large corporations. Such Model Rules have been adopted in certain jurisdictions in which the Company operates, including the United Kingdom, with an effective date of January 1, 2024. While the Company does not anticipate that Pillar Two will have a material impact on its effective tax rate, the Company will continue to evaluate the potential impacts of enacted and pending legislation in the jurisdictions in which it operates.

The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. The Company showed positive income over the three-year period ended December 31, 2023. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. The remaining U.S. valuation allowance relates primarily to foreign tax credit and capital loss carryforwards. For additional information regarding income taxes, refer to Note 11—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice. The Company is also under audit in various states and foreign jurisdictions as part of its normal course of business.

Potential Decommissioning Obligations on Sold Properties

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

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

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

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

As of December 31, 2023, Apache has incurred $819 million in decommissioning costs related to Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs. As of December 31, 2023, $293 million has been reimbursed from Trust A and $336 million has been reimbursed from the Letters of Credit. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

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

As of December 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $824 million to $1.2 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $824 million as of December 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $764 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $60 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.

As of December 31, 2023, the Company has also recorded a $199 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $21 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $178 million is reflected under “Other current assets.”

The Company recognized $212 million, $157 million, and $446 million during 2023, 2022, and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations.

On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division) which subsequently held that the sureties’ state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is void. Apache has drawn down the entirety of the Letters of Credit and is vigorously pursuing its claims against the sureties.

Insurance Program

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

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

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

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

Critical Accounting Estimates

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

Reserves Estimates

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

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

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

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

Oil and Gas Exploration Costs

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

Offshore Decommissioning Contingency

The Company has potential exposure to future obligations related to divested properties. For information regarding estimated potential decommissioning obligations on sold properties, please refer to “Potential Decommissioning Obligations on Sold Properties” above and in Note 12—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K.

The Company’s estimated contingent obligation is primarily associated with the abandonment, removal and decommissioning of offshore wells and platforms in the Gulf of Mexico. Estimating any future obligation requires significant judgment. The Company utilizes actual abandonment and decommissioning costs incurred as the basis to estimate the expected cash outflows for future obligations. Actual costs incurred often vary based on each structure’s condition, depth-of-water, type, and other similar factors, which are key considerations when estimating the remaining well and platform decommissioning obligation. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations. Changes in significant assumptions or the regulatory framework impacting the Company’s estimated liability could result in a liability in excess of the amount accrued.

Asset Retirement Obligation (ARO)

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

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

Income Taxes

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, the recent conflict in Israel and Gaza, actions taken by foreign oil and gas producing nations, including OPEC+, global inflation, and other current events.

The Company’s average crude oil price realizations decreased 19 percent to $80.83 per barrel in 2023 from $99.39 per barrel in 2022. The Company’s average natural gas price realizations decreased 40 percent to $2.96 per Mcf in 2023 from $4.97 per Mcf in 2022. The Company’s average NGL price realizations decreased 38 percent to $21.48 per barrel in 2023 from $34.62 per barrel in 2022. Based on average daily production for 2023, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $71 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $29 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $21 million.

Interest Rate Risk

At December 31, 2023, Apache had $4.8 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.34 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt.

The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its syndicated credit facilities. As of December 31, 2023, the Company had approximately $84 million in cash and cash equivalents, approximately 88 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2023, Apache had no borrowings outstanding under APA’s syndicated revolving credit facilities. Changes in the interest rate applicable to short-term investments and credit facility borrowings are expected to have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.

Foreign Currency Exchange Rate Risk

The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period. The Company monitors foreign currency exchange rates of countries in which it is conducting business and may, from time to time, implement measures to protect against foreign currency exchange rate risk.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. Foreign currency net gain or loss of $3 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 2023.


ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-60 in Part IV, Item 15 of this Annual Report on Form 10-K and are incorporated herein by reference.


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

The financial statements for the fiscal years ended December 31, 2023, 2022, and 2021, included in this Annual Report on Form 10-K, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.


ITEM 9A.			CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of December 31, 2023, the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

Management’s Annual Report on Internal Control Over Financial Reporting

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

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

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.


ITEM 9B.			OTHER INFORMATION

As of December 31, 2023, three were 1,000 shares of the Company’s common stock issued and outstanding, all of which were beneficially owned by APA. As a result, during the three months ended December 31, 2023, none of the Company’s directors or officers adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement” as each term is defined under Item 408 of Regulation S-K for the purchase or sale of shares of the Company’s common stock.


ITEM 9C.			DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III


ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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


ITEM 11.			EXECUTIVE COMPENSATION

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


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

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


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

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


ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES

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

PART IV


ITEM 15.			EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)Documents included in this report:


1.			Financial Statements


Report of management on internal control over financial reporting			F-1
Report of independent registered public accounting firm (PCAOB ID: 42)			F-2
Statement of consolidated operations for each of the three years in the period ended December 31, 2023			F-5
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2023			F-6
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2023			F-7
Consolidated balance sheet as of December 31, 2023 and 2022			F-8
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2023			F-9
Notes to consolidated financial statements			F-10


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


3.			Exhibits


		Incorporated by Reference
EXHIBIT NO.	DESCRIPTION	Form	Exhibit	Filing Date	SEC File No.
2.1	Agreement and Plan of Merger, dated as of March 1, 2021, by and among Registrant, APA Corporation, and APA Merger Sub, Inc.	8-K	2.1	3/1/2021	001-04300
3.1	Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as attached as Annex A to the Certificate of Merger of APA Merger Sub, Inc. with and into Registrant, filed with the Secretary of State of the State of Delaware on March 1, 2021.	8-K	3.1	3/1/2021	001-04300
3.2	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated June 7, 2021, filed with the Secretary of State of the State of Delaware on June 10, 2021.	8-K	3.1	6/14/2021	001-04300
3.3	Amended and Restated Bylaws of Registrant, dated March 1, 2021.	8-K	3.2	3/1/2021	001-04300
4.1	Form of Certificate for Registrant’s Common Stock.	10-Q	4.1	5/9/2014	001-04300
4.2	Form of 7.70% Notes due 2026.	8-K	4.1	2/23/1996	001-04300
4.3	Form of 7.95% Notes due 2026.	8-K	4.1	4/23/1996	001-04300
4.4	Form of 7.625% Debentures due 2096.	8-K	4.2	11/4/1996	001-04300
4.5	Form of 7.375% Debentures due 2047.	8-K	4.1	8/8/1997	001-04300
4.6	Form of 6.000% Notes due 2037.	8-K	4.2	1/26/2007	001-04300
4.7	Form of 5.250% Notes due 2042.	8-K	4.2	12/3/2010	001-04300
4.8	Form of 5.100% Notes due 2040.	8-K	4.1	8/20/2010	001-04300
4.9	Form of 4.75% Notes due 2043.	8-K	4.3	4/9/2012	001-04300
4.10	Form of 4.250% Notes due 2044.	8-K	4.2	12/4/2012	001-04300
4.11	Form of 4.375% Notes due 2028.	8-K	4.1	8/16/2018	001-04300
4.12	Form of 4.250% Notes due 2030.	8-K	4.1	6/10/2019	001-04300
4.13	Form of 5.350% Notes due 2049.	8-K	4.2	6/10/2019	001-04300
4.14	Form of 4.625% Notes due 2025.	8-K	4.1	8/6/2020	001-04300
4.15	Form of 4.875% Notes due 2027.	8-K	4.2	8/6/2020	001-04300
4.16	Form of 7.75% Notes due December 15, 2029.	8-K/A	4.1	12/14/1999	001-04300
4.17	Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees.	S-3	4.6	5/23/2003	333-105536
4.18	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees.	S-3	4.7	5/23/2003	333-105536
4.19	Second Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank, formerly Chemical Bank), as trustee under Indenture, dated as of February 15, 1996, as previously amended and supplemented.	10-K	4.15	2/28/2020	001-04300


		Incorporated by Reference
EXHIBIT NO.	DESCRIPTION	Form	Exhibit	Filing Date	SEC File No.
4.20	Form of Indenture among Registrant, Apache Finance Canada Corporation, and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees.	S-3/A	4.1	11/12/1999	333-90147
4.21	Supplemental Indenture, dated as of August 14, 2017, among Apache Finance Canada Corporation, Apache Corporation, and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee.	10-Q	4.1	11/3/2017	001-04300
4.22	Second Supplemental Indenture, dated as of December 16, 2019, between Apache Corporation (as successor to Apache Finance Canada Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee under Indenture, dated as of November 23, 1999, as previously amended and supplemented.	10-K	4.18	2/28/2020	001-04300
4.23	Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation.	S-3	4.14	5/23/2011	333-174429
4.24	Supplemental Indenture, dated as of December 16, 2019, between Apache Corporation and Wells Fargo Bank, National Association, as trustee under Indenture, dated as of May 19, 2011.	10-K	4.20	2/28/2020	001-04300
4.25	Indenture, dated August 14, 2018, by and between Apache Corporation and Wells Fargo Bank, National Association, as trustee.	S-3/A	4.5	8/14/2018	333-219345
10.1	Guaranty, dated as of January 30, 2024, made by Apache Corporation in favor of each of the lenders and agents party to the Credit Agreement, dated as of January 30, 2024, among APA Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.1	1/30/2024	001-04300
10.2	Credit Agreement, dated as of January 30, 2024, among APA Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.2	1/30/2024	001-04300
10.3	Guaranty [USD Facility], dated as of April 29, 2022, made by Apache Corporation in favor of each of the lenders, issuing banks, and agents party to the Credit Agreement, dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.1	5/2/2022	001-04300
10.4	Credit Agreement [USD Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.2	5/2/2022	001-04300
10.5	Guaranty [GBP Facility], dated as of April 29, 2022, made by Apache Corporation in favor of each of the lenders, issuing banks, and agents party to the Credit Agreement, dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.3	5/2/2022	001-04300
10.6	Credit Agreement [GBP Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto.	8-K	10.4	5/2/2022	001-04300

Incorporated by Reference

EXHIBIT
NO.

DESCRIPTION

Form

Exhibit

Filing Date

SEC File No.

†10.7

Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated, effective January 1, 2015.

10-Q

10.2

8/8/2014

001-04300

†10.8

Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, effective August 1, 2020.

10-Q

10.1

11/5/2020

001-04300

†10.9

Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, effective March 1, 2021.

8-K

10.3

3/1/2021

001-04300

†10.10

Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, as amended and restated, effective January 1, 2015.

10-Q

10.3

8/8/2014

001-04300

†10.11

Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, effective March 1, 2021.

8-K

10.4

3/1/2021

001-04300

*23.1

Consent of Ryder Scott Company, L.P., Petroleum Consultants.

*24.1

Power of Attorney (included as a part of the signature pages to this report).

*31.1

Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

*31.2

Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

**32.1

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

*99.1

Report of Ryder Scott Company, L.P., Petroleum Consultants.

*101.INS

Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).

*101.SCH

Inline XBRL Taxonomy Schema Document.

*101.CAL

Inline XBRL Calculation Linkbase Document.

*101.DEF

Inline XBRL Definition Linkbase Document.

*101.LAB

Inline XBRL Label Linkbase Document.

*101.PRE

Inline XBRL Presentation Linkbase Document.

*104

Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).


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

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


ITEM 16.			FORM 10-K SUMMARY

None.

SIGNATURES

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

APACHE CORPORATION

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer

Dated: February 22, 2024

POWER OF ATTORNEY

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

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

Name

Title

Date

/s/ John J. Christmann IV

John J. Christmann IV

Director and Chief Executive Officer

(principal executive officer)

February 22, 2024

/s/ Stephen J. Riney

Stephen J. Riney

President and Chief Financial Officer

(principal financial officer)

February 22, 2024

/s/ Rebecca A. Hoyt

Rebecca A. Hoyt

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

February 22, 2024

/s/ Clay Bretches

Clay Bretches

Director and Executive Vice President, Operations

February 22, 2024

/s/ David A. Pursell

David A. Pursell

Director and Executive Vice President, Development

February 22, 2024

/s/ Mark D. Maddox

Mark D. Maddox

Director and Executive Vice President, Administration

February 22, 2024

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2023.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-4.


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

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

/s/ Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer and Controller
(principal accounting officer)

Houston, Texas

February 22, 2024

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and the Board of Directors of Apache Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries (the Company) as of December 31, 2023 and 2022, the related statements of consolidated operations, comprehensive income (loss), cash flows and changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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

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

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

Critical Audit Matters

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


						Depreciation, depletion and amortization of property and equipment
Description of the Matter						At December 31, 2023, the carrying value of the Company’s property and equipment was $8,724 million, and depreciation, depletion and amortization (DD&A) expense was $1,399 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers.

F-2


						Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Judgment is required by the Company’s internal reservoir engineers in evaluating data used when estimating oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for select properties as of December 31, 2023. Auditing the Company’s DD&A calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.

How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates for select properties. In addition, in assessing whether we can use the work of the engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. We also tested the mathematical accuracy of the DD&A calculation, including comparing the oil and gas reserve amounts used in the calculation to the Company’s reserve reports.
						Accounting for asset retirement obligation for the North Sea segment
Description of the Matter						At December 31, 2023, the asset retirement obligation (ARO) balance totaled $2,430 million. As further described in Note 9, the Company’s ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs. Auditing the Company’s ARO for the North Sea segment is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to retirement cost estimates, which are affected by expectations about future market and economic conditions.

F-3


How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation. To test the ARO for the North Sea segment, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs. We also involved our internal specialists in testing the underlying retirement cost estimates.
						Accounting for decommissioning contingency for sold Gulf of Mexico properties
Description of the Matter						At December 31, 2023, the decommissioning contingency for sold Gulf of Mexico properties (decommissioning contingency) balance totaled $824 million. As further described in Note 12, the Company’s decommissioning contingency reflects the estimated undiscounted potential liability to fund decommissioning of the sold Gulf of Mexico properties. The estimation of the decommissioning contingency requires significant judgment given the magnitude and higher estimation uncertainty of the expected retirement costs. Auditing the Company’s decommissioning contingency is complex and highly judgmental because of the significant estimation required by management in determining the decommissioning contingency. In particular, the estimate was sensitive to retirement cost estimates, which are subjective assumptions affected by expectations about future market and economic conditions.

How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its decommissioning contingency estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the contingency. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation. To test the decommissioning contingency, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs. We also involved our internal specialists in testing the underlying retirement cost estimates.

/s/ Ernst & Young LLP

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

Houston, Texas

February 22, 2024

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS


	For the Year Ended December 31,
	2023		2022		2021

	(In millions, except per common share data)
REVENUES AND OTHER:
Oil, natural gas, and natural gas liquids production revenues(1)	$	7,079	$	9,028	$	6,498
Purchased oil and gas sales(1)	894		1,855		1,487
Total revenues	7,973		10,883		7,985
Derivative instrument gains (losses), net	—		(107)		94
Gain on divestitures, net	8		1,180		67
Losses on previously sold Gulf of Mexico properties	(212)		(157)		(446)
Other, net	26		139		228
	7,795		11,938		7,928
OPERATING EXPENSES:
Lease operating expenses(1)	1,397		1,435		1,241
Gathering, processing, and transmission(1)	314		356		264
Purchased oil and gas costs(1)	742		1,776		1,580
Taxes other than income	192		256		204
Exploration	153		146		127
General and administrative	325		462		357
Transaction, reorganization, and separation	15		26		22
Depreciation, depletion, and amortization	1,399		1,177		1,360
Asset retirement obligation accretion	116		117		113
Impairments	61		—		208
Financing costs, net	165		313		472
	4,879		6,064		5,948
NET INCOME BEFORE INCOME TAXES	2,916		5,874		1,980
Current income tax provision	1,338		1,507		652
Deferred income tax provision (benefit)	(1,652)		145		(74)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	3,230		4,222		1,402
Net income attributable to noncontrolling interest – Sinopec	352		464		174
Net income attributable to noncontrolling interest – Altus	—		14		4
Net income attributable to noncontrolling interest – APA Corporation	352		278		—
Net income (loss) attributable to Altus Preferred Unit limited partners	—		(70)		162
NET INCOME ATTRIBUTABLE TO APACHE CORPORATION	$	2,526	$	3,536	$	1,062

(1) For related party transactions associated with Kinetik, refer to Note 7—Equity Method Interest for further detail.

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

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$	3,230	$	4,222	$	1,402
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	1		(8)		7
Share of equity method interests other comprehensive income	—		—		1
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	3,231		4,214		1,410
Comprehensive income attributable to noncontrolling interest – Sinopec	352		464		174
Comprehensive income attributable to noncontrolling interest – Altus	—		14		4
Comprehensive income attributable to noncontrolling interest – APA Corporation	352		278		—
Comprehensive income (loss) attributable to Altus Preferred Unit limited partners	—		(70)		162
COMPREHENSIVE INCOME ATTRIBUTABLE TO APACHE CORPORATION	$	2,527	$	3,528	$	1,070

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$	3,230	$	4,222	$	1,402
Adjustments to reconcile net income to net cash provided by operating activities:

Unrealized derivative instrument losses (gains), net	—		23		(69)
Gain on divestitures, net	(8)		(1,180)		(67)
Exploratory dry hole expense and unproved leasehold impairments	108		92		86
Depreciation, depletion, and amortization	1,399		1,177		1,360
Asset retirement obligation accretion	116		117		113
Impairments	61		—		208
Provision for (benefit from) deferred income taxes	(1,652)		145		(74)
(Gain) loss from extinguishment of debt	(9)		67		104
Losses on previously sold Gulf of Mexico properties	212		157		446
Other	(85)		(137)		(23)
Changes in operating assets and liabilities:
Receivables	(146)		(55)		(393)
Inventories	13		(1)		(9)
Drilling advances and other current assets	287		(12)		60
Deferred charges and other long-term assets	269		70		(42)
Accounts payable	(86)		12		205
Receivable/payable with APA Corporation	(52)		—		40
Accrued expenses	(401)		293		127
Deferred credits and noncurrent liabilities	(327)		(138)		31
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,929		4,852		3,505
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to upstream oil and gas property	(1,931)		(1,503)		(934)

Leasehold and property acquisitions	(20)		(37)		(9)
Noncurrent receivable from APA Corporation	(680)		(832)		—

Proceeds from asset divestitures	29		778		256
Proceeds from sale of Kinetik shares	228		224		—
Deconsolidation of Altus cash and cash equivalents	—		(143)		—
Other, net	(38)		28		21
NET CASH USED IN INVESTING ACTIVITIES	(2,412)		(1,485)		(666)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Apache credit facility, net	—		138		392
Proceeds from (payments on) note payable to APA Corporation, net	—		(835)		78

Payments on fixed-rate debt	(65)		(1,493)		(1,795)
Distributions to noncontrolling interest – Sinopec	(238)		(362)		(279)
Distributions to APA Corporation	(315)		(894)		(1,182)
Dividends paid	—		—		(9)

Other, net	—		(15)		(27)
NET CASH USED IN FINANCING ACTIVITIES	(618)		(3,461)		(2,822)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(101)		(94)		17
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	185		279		262
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	84	$	185	$	279
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	293	$	322	$	442
Income taxes paid, net of refunds	1,271		1,431		633
Non-cash financing adjustment: APA’s assumption of Apache’s borrowings on its syndicated credit facility	—		680		—

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
	2023		2022

	(In millions, except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	84	$	185
Receivables, net of allowance of $114 and $117	1,559		1,424
Other current assets (Note 6)	725		993
Accounts receivable from APA Corporation	52		—
	2,420		2,602
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:	43,349		41,245


Gathering, processing, and transmission facilities	448		449
Other	634		613

Less: Accumulated depreciation, depletion, and amortization	(35,707)		(34,350)
	8,724		7,957
OTHER ASSETS:
Equity method interests (Note 7)	437		624
Decommissioning security for sold Gulf of Mexico properties (Note 12)	21		217
Deferred tax asset (Note 11)	1,747		39
Deferred charges and other	522		532
Noncurrent receivable from APA Corporation (Note 2)	93		869
Note receivable from APA Corporation (Note 2)	2,980		1,415
	$	16,944	$	14,255

LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	560	$	646

Current debt	2		2
Other current liabilities (Note 8)	1,669		2,049
	2,231		2,697
LONG-TERM DEBT (Note 10)	4,814		4,885
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 11)	371		314
Asset retirement obligation (Note 9)	2,354		1,936
Decommissioning contingency for sold Gulf of Mexico properties (Note 12)	764		738
Other	466		443
	3,955		3,431


EQUITY:
Common stock, $0.625 par, 1,000 and 1,000 shares authorized, respectively, 1,000 and 1,000 shares issued, respectively	—		—
Paid-in capital	7,972		8,025
Accumulated deficit	(3,255)		(5,781)

Accumulated other comprehensive income	15		14
EQUITY ATTRIBUTABLE TO APACHE CORPORATION	4,732		2,258
Noncontrolling interest – Sinopec	1,036		922
Noncontrolling interest – APA Corporation	176		62
TOTAL EQUITY	5,944		3,242
	$	16,944	$	14,255

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

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


	Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners		Common Stock		Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Income (Loss)		PARENT COMPANY EQUITY (DEFICIT)		Noncontrolling Interests		TOTAL EQUITY (DEFICIT)

	(In millions)
BALANCE AT DECEMBER 31, 2020	$	608	$	262	$	11,735	$	(10,461)	$	(3,189)	$	14	$	(1,639)	$	994	$	(645)
Net income attributable to Apache Corporation	—		—		—		1,062		—		—		1,062		—		1,062
Net income attributable to noncontrolling interest – Sinopec	—		—		—		—		—		—		—		174		174
Net income attributable to noncontrolling interest – Altus	—		—		—		—		—		—		—		4		4
Net income attributable to Altus Preferred Unit limited partners	162		—		—		—		—		—		—		—		—
Distributions payable to Altus Preferred Unit limited partners	(12)		—		—		—		—		—		—		—		—
Distributions paid to Altus Preferred Unit limited partners	(46)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(279)		(279)
Distributions to APA Corporation	—		—		(890)		—		—		—		(890)		—		(890)
Common dividends ($0.025 per share)	—		—		(9)		—		—		—		(9)		—		(9)
APA Corporation share exchange	—		(262)		(2,927)		—		3,189		—		—		—		—
Holding Company Reorganization	—		—		757		82		—		—		839		—		839
Other	—		—		11		—		—		8		19		(15)		4
BALANCE AT DECEMBER 31, 2021	$	712	$	—	$	8,677	$	(9,317)	$	—	$	22	$	(618)	$	878	$	260
Net income attributable to Apache Corporation	—		—		—		3,536		—		—		3,536		—		3,536
Net income attributable to noncontrolling interest – APA	—		—		—		—		—		—		—		278		278
Net income attributable to noncontrolling interest – Sinopec	—		—		—		—		—		—		—		464		464
Net income attributable to noncontrolling interest – Altus	—		—		—		—		—		—		—		14		14
Net loss attributable to Altus Preferred Unit limited partners	(70)		—		—		—		—		—		—		—		—
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(362)		(362)
Distributions to APA Corporation	—		—		(678)		—		—		—		(678)		(216)		(894)
Deconsolidation of Altus	(642)		—		—		—		—		—		—		(72)		(72)
Other	—		—		26		—		—		(8)		18		—		18
BALANCE AT DECEMBER 31, 2022	$	—	$	—	$	8,025	$	(5,781)	$	—	$	14	$	2,258	$	984	$	3,242
Net income attributable to Apache Corporation	—		—		—		2,526		—		—		2,526		—		2,526
Net income attributable to noncontrolling interest – APA	—		—		—		—		—		—		—		352		352
Net income attributable to noncontrolling interest – Sinopec	—		—		—		—		—		—		—		352		352
Distributions to noncontrolling interest – Egypt	—		—		—		—		—		—		—		(238)		(238)

Distributions to APA Corporation	—		—		(77)		—		—		—		(77)		(238)		(315)
Other	—		—		24		—		—		1		25		—		25
BALANCE AT DECEMBER 31, 2023	$	—	$	—	$	7,972	$	(3,255)	$	—	$	15	$	4,732	$	1,212	$	5,944

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

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations

Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has oil and gas operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). Prior to the BCP Business Combination defined below, Apache’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of Apache’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’s operating and legal structure, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2—Transactions with Parent Affiliate for more detail.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Principles of Consolidation

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

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

In conjunction with the ratification of a merged concession agreement with the Egyptian General Petroleum Corporation (EGPC) in December 2021, Apache modified partnership agreements for certain consolidated subsidiaries. Apache subsequently determined that one of its limited partnership subsidiaries, which has control over Apache’s Egyptian operations, qualified as a variable interest entity (VIE) under GAAP. Apache continues to consolidate this limited partnership subsidiary because the Company has concluded that it has a controlling financial interest in the Egyptian operations and was determined to be the primary beneficiary of the VIE. For all periods presented, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) has owned a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest. Under the modified partnership agreements, APA owns a noncontrolling interest participation in the remaining two-thirds of its consolidated Egypt oil and gas business. Refer to Note 2—Transactions with Parent Affiliate for detail regarding APA’s noncontrolling interest. All noncontrolling interests are reflected as a separate component of equity in the Company’s consolidated balance sheet.

Additionally, prior to the BCP Business Combination (as defined below), third-party investors owned a minority interest of approximately 21 percent of Altus, which was reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. ALTM qualified as a VIE under GAAP, which Apache consolidated because a wholly owned subsidiary of Apache had a controlling financial interest and was determined to be the primary beneficiary.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Pursuant to the BCP Contribution Agreement, the Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and the Company determined that it was no longer the primary beneficiary of Kinetik. The Company further determined that Kinetik no longer qualified as a VIE under GAAP. As a result, the Company deconsolidated ALTM on February 22, 2022. Refer to Note 3—Acquisitions and Divestitures for further detail.

During each of the years ended December 31, 2023 and 2022, the Company had a designated director on the Kinetik board of directors. As a result, the Company is considered to have had significant influence over Kinetik for all periods presented and will continue to have such influence until such time as Kinetik appoints a replacement for the Company’s designated director, given that the Company’s current beneficial ownership percentage in Kinetik no longer entitles it to designate a director to the Kinetik board.

Investments in which the Company has significant influence, but not control, are accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company elected the fair value option to account for its equity method interest in Kinetik. Refer to Note 7—Equity Method Interests for further detail.

Use of Estimates

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

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

Fair Value Measurements

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

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

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Recurring fair value measurements are presented in further detail in Note 5—Derivative Instruments and Hedging Activities, Note 7—Equity Method Interests, Note 10—Debt and Financing Costs, Note 13—Retirement and Deferred Compensation Plans, and Note 14—Redeemable Noncontrolling Interest — Altus.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment.

For the years ended December 31, 2023 and 2022, the Company recorded $11 million and no asset impairments, respectively, in connection with fair value assessments.

For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in a pipeline investment as part of Altus’ review of the fair value of its assets in relation to the BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 3—Acquisitions and Divestitures for further detail on the BCP Business Combination.

Revenue Recognition

Upstream

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

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

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

Altus Midstream

Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Altus Midstream segment was operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generated revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represented a single, distinct performance obligation on behalf of Altus that was satisfied over time. In accordance with the terms of these agreements, Altus primarily received a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue was primarily measured using the output method and recognized in the amount to which Altus had the right to invoice, as performance completed to date corresponded directly with the value to its customers. For the periods prior to the BCP Business Combination, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which were fully eliminated upon consolidation.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Payment Terms and Contract Balances

Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $1.4 billion and $1.3 billion as of December 31, 2023 and 2022, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Over the past year, the Company experienced a gradual decline in the timeliness of receipts from the EGPC for the Company’s Egyptian oil and gas sales. Although the Company continues to receive periodic payments from EGPC, deteriorating economic conditions in Egypt have lessened the availability of U.S. dollars in Egypt, resulting in a delay in receipts from EGPC. Continuation of the currency shortage in Egypt could lead to further delays, deferrals of payment, or non-payment in the future; however, the Company currently anticipates that it will ultimately be able to collect its receivable from EGPC.

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

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2023 and 2022, the Company had $84 million and $185 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2023 and 2022.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity.

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Allowance for credit loss at beginning of year	$	117	$	109	$	95
Additional provisions for the year	16		9		19
Uncollectible accounts written off, net of recoveries	(19)		(1)		(5)
Allowance for credit loss at end of year	$	114	$	117	$	109

Receivable from / Payable to APA

Receivable from or payable to APA represents the net result of Apache’s administrative and support services provided to APA and other miscellaneous cash management transactions to be settled between the two affiliated entities. Cash will be transferred to Apache or paid to APA over time in order to manage affiliate balances for cash management purposes. Refer to Note 2—Transactions with Parent Affiliate for more detail.

Inventories

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

During 2023, the Company recorded $50 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

Property and Equipment

The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Unproved properties:
U.S.	$	10	$	20	$	22
Egypt	—		4		8
North Sea	11		—		1
Total unproved properties	$	21	$	24	$	31

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of proved properties.

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

Gathering, Processing, and Transmission (GPT) Facilities

GPT facilities totaled $448 million and $449 million at December 31, 2023 and 2022, respectively, with accumulated depreciation for these assets totaling $373 million and $367 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether Apache-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

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

For the years ended December 31, 2023, 2022, and 2021, the Company recorded no impairments of GPT facilities.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $217 million and $206 million at December 31, 2023 and 2022, respectively.

Asset Retirement Costs and Obligations

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

Capitalized Interest

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

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Equity Method Interests

The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company. Refer to Note 7—Equity Method Interests for further details of the Company’s equity method interests.

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Prior to the deconsolidation of Altus on February 22, 2022, in the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the BCP Business Combination, determined the fair value of a pipeline investment was below carrying value. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in the pipeline.

Commitments and Contingencies

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

Derivative Instruments and Hedging Activities

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

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

Income Taxes

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

Apache is a directly owned subsidiary of APA and is included in APA and its subsidiaries’ U.S. Federal income tax return. The Company’s financial statements recognize the current and deferred income tax consequences that result from Apache’s activities during the current period pursuant to the provisions of ASC Topic 740 “Income Taxes” as if the Company were a separate taxpayer rather than a member of APA’s consolidated income tax return group. Refer to Note 11—Income Taxes for further information.

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Stock-Based Compensation

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

Transaction, Reorganization, and Separation (TRS)

The Company recorded TRS costs in 2023, 2022, and 2021 totaling $15 million, $26 million, and $22 million, respectively, including $7 million, $15 million, and $17 million, respectively, related to ongoing consulting and separation costs in international operations associated with the redesign of the Company’s organizational structure and operations.

New Pronouncements Issued But Not Yet Adopted

In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, “Segment Reporting (Topic 280),” which expands disclosures about a public entity’s reportable segments and requires more enhanced information about a reportable segment’s expenses, interim segment profit or loss, and how a public entity’s chief operating decision maker uses reported segment profit or loss information in assessing segment performance and allocating resources. The amendments do not change or remove existing disclosure requirements or how a public entity identifies its operating segments, aggregates those operating segments, or applies the quantitative thresholds to determine its reportable segments. The amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted, and the amendments are required to be applied on a retrospective basis. The Company is currently assessing the impact of adopting this standard and does not believe this will have a material impact on its financial statements.

In December 2023, the FASB issued ASU 2023-09 “Improvements to Income Tax Disclosures (Topic 740),” which requires enhanced disclosures primarily related to existing rate reconciliation and income taxes paid information. This update is effective for the Company beginning in the first quarter of 2025 and is applied on a prospective basis. Retrospective application is also permitted. The Company does not believe this will have a material impact on its financial statements.

2. TRANSACTIONS WITH PARENT AFFILIATE

Apache is a direct, wholly owned subsidiary of APA. Apache holds assets in the U.S., Egypt, and the U.K. and provides administrative and support operations for certain APA subsidiaries with interests in the U.S., Suriname, and other international locations. The Company incurred $22 million, $18 million, and $17 million during 2023, 2022, and 2021, respectively, in reimbursable corporate overhead charges in connection with these administration and support operations.

Notes Receivable from APA Corporation

On March 1, 2021, Apache sold to APA all of the equity in the three Apache subsidiaries through which Apache’s interests in Suriname and the Dominican Republic were held. The purchase price is payable pursuant to a senior promissory note made by APA payable to Apache, dated March 1, 2021. The note has a seven-year term, maturing on February 29, 2028, and bears interest at a rate of 4.5 percent per annum, payable semi-annually, subject to APA’s option to allow accrued interest to convert to principal (PIK) during the first 5.5 years of the note’s term (to August 31, 2026). The note is guaranteed by each of the three subsidiaries sold by Apache to APA. APA allowed interest accrued from March 1, 2021 through August 31, 2023, totaling $158 million, to PIK pursuant to the note. As of December 31, 2023 and 2022, approximately $1.5 billion and $1.4 billion, respectively, were in principal outstanding under this note.

In April 2022, Apache made a promissory note payable to APA in the original principal amount of $680 million. Apache made the note in consideration for APA’s assumption under its U.S. dollar denominated syndicated facility on April, 29, 2022 of Apache’s borrowings outstanding upon the simultaneous termination of its 2018 syndicated facility, as described in Note 1 0 —Debt and Financing Costs. The non-interest-bearing note was fully repaid during 2022.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

APA also made a senior promissory note payable to Apache, dated March 31, 2023, pursuant to which Apache may loan and APA may borrow, repay, and reborrow up to $1.5 billion in aggregate principal amount outstanding at any time. The note has a five-year term, maturing March 31, 2028. The note bears interest at a rate per annum of 6.0 percent, payable semi-annually; however, APA may allow accrued interest to convert to principal, subject to the aggregate maximum principal amount of the note. As of December 31, 2023, there were $1.5 billion in borrowings outstanding under this note. The note is intended to facilitate cash management of APA and Apache.

These notes are both reflected in “Notes receivable from APA Corporation” on the Company’s consolidated balance sheet. The Company recognized interest income on these notes totaling $109 million, $63 million, and $51 million during 2023, 2022, and 2021, respectively. The interest income related to these notes is reflected in “Financing costs, net” on the Company’s statement of consolidated operations.

Noncontrolling Interest – APA Corporation

In the fourth quarter of 2021, in conjunction with the ratification of a new merged concession agreement (MCA) with the EGPC, Apache entered into an agreement with APA under which the historical value of existing concessions prior to ratifying the MCA was retained by Apache, with any excess value from the MCA terms being allocated to APA. Sinopec owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business, and 50 percent of the remaining net income and distributable cash flow for the Company’s Egyptian operations was allocated to APA in 2023. Apache consolidates its Egyptian operations, with APA’s noncontrolling interest reflected as a separate component in the Company’s consolidated balance sheet. The Company recorded net income attributable to APA’s noncontrolling interest of $352 million and $278 million during 2023 and 2022, respectively. The Company also distributed $238 million and $216 million during 2023 and 2022, respectively, of cash to APA in association with its noncontrolling interest.

Accounts Receivable from / Accounts Payable to APA

In connection with the Company’s role as service provider to APA, Apache is reimbursed by APA for employee costs, certain internal costs, and third-party costs paid by the Company on behalf of APA. All reimbursements are based on actual costs incurred, and no market premium is applied by the Company to APA. The Company also collects third-party receivables on behalf of APA. As of December 31, 2023, the Company had accounts receivable from APA in connection with these services totaling $52 million, which is reflected in “Accounts receivable from APA Corporation” on the Company’s consolidated balance sheet.

As of December 31, 2023 and 2022, the Company also had receivables from APA totaling $93 million and $869 million, respectively, which were incorporated into the senior promissory note dated March 31, 2023 discussed above during 2024 and 2023, respectively. These balances are reflected in “Noncurrent receivable from APA Corporation.”

Other Transactions with APA Corporation

From time to time, the Company may, at its discretion, make distributions of capital to APA. During 2023 and 2022, the Company made capital distributions totaling $77 million and $678 million, respectively, primarily in support of dividend payments and capital transactions completed by APA during the respective periods.

3. ACQUISITIONS AND DIVESTITURES

2023 Activity

In December 2023, the Company sold 7.5 million of its shares of Kinetik Class A Common Stock (Kinetik Shares) for cash proceeds of $228 million. Refer to Note 7—Equity Method Interests for further detail.

During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $20 million.

During 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $29 million, recognizing an aggregate gain of approximately $8 million upon closing of these transactions.

2022 Activity

During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million, recognizing an aggregate gain of approximately $36 million, upon closing of these transactions.

During 2022, the Company completed the sale of certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million.

The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed.

As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s $193 million net effect of deconsolidating ALTM’s balance sheet and the $802 million fair value of the Company’s approximate 20 percent retained ownership in the combined entity.

During the first quarter of 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 7—Equity Method Interests for further detail.

2021 Activity

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

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

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

4. CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2023, 2022, and 2021. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Capitalized well costs at beginning of year	$	50	$	46	$	197
Additions pending determination of proved reserves	150		138		62
Divestitures and other	—		—		(163)
Reclassifications to proved properties	(135)		(110)		(40)
Charged to exploration expense	(18)		(24)		(10)
Capitalized well costs at end of year	$	47	$	50	$	46

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	2023		2022		2021

	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	38	$	34	$	13
Exploratory well costs capitalized for a period greater than one year	9		16		33
Capitalized well costs at end of year	$	47	$	50	$	46

Number of projects with exploratory well costs capitalized for a period greater than one year	8		10		9

Projects with exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Exploratory well costs capitalized for a period greater than one year since completion of drilling were $9 million at December 31, 2023. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing.

Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2022 totaled $16 million. These expenses pertained to projects in the North Sea and Egypt.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2023, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:


	Total		2022		2021		2020 and Prior

	(In millions)

Egypt	$	9	$	—	$	—	$	9

	$	9	$	—	$	—	$	9

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company may utilize various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.

In December 2022, counterparty agreements for Apache’s commodity derivative instruments were transferred from Apache to APA. Apache had no outstanding derivative positions as of December 31, 2023 or December 31, 2022.

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivative Activity Recorded in the Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Realized:
Commodity derivative instruments	$	—	$	(72)	$	25

Foreign currency derivative instruments	—		(13)		—

Realized gains (losses), net	—		(85)		25
Unrealized:
Commodity derivative instruments	—		9		(20)
Pipeline capacity embedded derivatives	—		—		7

Preferred Units embedded derivative	—		(31)		82
Unrealized gains (losses), net	—		(22)		69
Derivative instrument gains (losses), net	$	—	$	(107)	$	94

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

6. OTHER CURRENT ASSETS

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


	2023		2022

	(In millions)
Inventories	$	439	$	425
Drilling advances	68		64
Prepaid assets and other	40		54
Current decommissioning security for sold Gulf of Mexico assets	178		450
Total Other current assets	$	725	$	993

7. EQUITY METHOD INTERESTS

As of December 31, 2023 and 2022, the Company recorded $437 million and $624 million, respectively, for ownership of its Kinetik Shares. The Company’s Kinetik Shares are treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.

The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million Kinetik Shares as of February 22, 2022. In March 2022, the Company sold four million of its Kinetik Shares for cash proceeds of $224 million. Refer to Note 3–Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock, resulting in the Company owning approximately 17.7 million Kinetik Shares. In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $228 million.

The Company has received approximately 2.9 million Kinetik Shares as paid-in-kind dividends through December 31, 2023. As of December 31, 2023, the Company owned 13.1 million Kinetik Shares, representing approximately 9 percent of Kinetik’s outstanding common stock.

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company recorded changes in the fair value of its equity method interest in Kinetik totaling gains of $41 million and $72 million during 2023 and 2022, respectively. The balance of the Company’s equity method interest in Kinetik was also impacted by the sales of Kinetik Shares noted above during 2023 and 2022.

The following table represents related party sales and costs associated with Kinetik:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Natural gas and NGLs sales	$	64	$	8
Purchased oil and gas sales	29		—
	$	93	$	8

Gathering, processing, and transmission costs	$	99	$	91
Purchased oil and gas costs	80		—
Lease operating expenses	7		—
	$	186	$	91

As of December 31, 2023 and 2022, the Company has recorded accrued costs payable to Kinetik of approximately $27 million and $17 million, respectively, and accrued receivables from Kinetik of approximately $13 million and $8 million, respectively.

8. OTHER CURRENT LIABILITIES

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


	2023		2022

	(In millions)
Accrued operating expenses	$	158	$	139
Accrued exploration and development	307		300

Accrued compensation and benefits	390		514
Accrued interest	92		96
Accrued income taxes	138		90
Current asset retirement obligation	76		55
Current operating lease liability	115		167

Current decommissioning contingency for sold Gulf of Mexico properties	60		450
Other	333		238
Total Other current liabilities	$	1,669	$	2,049

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2023 and 2022:


	For the Year Ended December 31,
	2023		2022

	(In millions)
Asset retirement obligation at beginning of the year	$	1,991	$	2,130
Liabilities incurred	12		4

Liabilities divested	—		(73)
Liabilities settled	(45)		(39)
Accretion expense	116		117
Revisions in estimated liabilities	356		(148)

Asset retirement obligation at end of the year	2,430		1,991
Less current portion	(76)		(55)
Asset retirement obligation, long-term	$	2,354	$	1,936

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

During 2023 and 2022, the Company recorded $12 million and $4 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2023, net abandonment costs were revised upward by approximately $356 million, primarily reflecting changes in estimates of timing, activity costs, and foreign currency exchange rates on service costs in the North Sea. During 2022, net abandonment costs were revised downward by approximately $148 million to reflect changes in estimates of timing and foreign currency exchange rates on service costs, primarily in the North Sea, partially offset by an upward revision in the U.S.

10. DEBT AND FINANCING COSTS

Overview

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

During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the US dollar-denominated revolving credit facility of APA Corporation described below.

On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed in part by Apache’s borrowing under the U.S. dollar-denominated revolving credit facility of APA Corporation described below.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

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

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

Apache intends to reduce debt outstanding under its indentures from time to time.

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

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the carrying value of the Company’s debt as of December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)




4.625% notes due 2025(1)	$	51	$	51
7.7% notes due 2026	78		78
7.95% notes due 2026	132		132
4.875% due 2027(1)	108		108
4.375% notes due 2028(1)	325		325
7.75% notes due 2029(1)(2)	235		235
4.25% notes due 2030(1)	516		579
6.0% notes due 2037(1)	443		443
5.1% notes due 2040(1)	1,333		1,333
5.25% notes due 2042(1)	399		399
4.75% notes due 2043(1)	428		428
4.25% notes due 2044(1)	211		221
7.375% debentures due 2047	150		150
5.35% notes due 2049(1)	387		387
7.625% debentures due 2096	39		39
Notes and debentures before unamortized discount and debt issuance costs(3)	4,835		4,908


Finance lease obligations	32		34
Unamortized discount	(26)		(27)
Debt issuance costs	(25)		(28)
Total debt	4,816		4,887
Current maturities	(2)		(2)
Long-term debt	$	4,814	$	4,885

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

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

(3)The fair values of Apache’s notes and debentures were $4.3 billion and $4.2 billion as of December 31, 2023 and 2022, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2023 are as follows:


	(In millions)
2024	$	—
2025	51
2026	210
2027	108
2028	325
Thereafter	4,141
Notes and debentures, excluding discounts and debt issuance costs	$	4,835

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Financing Costs, Net

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Interest expense	$	291	$	312	$	419
Amortization of debt issuance costs	2		7		8
Capitalized interest	—		(1)		—
Loss (gain) on extinguishment of debt	(9)		67		104
Interest income	(10)		(9)		(8)
Interest income from APA Corporation, net	(109)		(63)		(51)
Financing costs, net	$	165	$	313	$	472

Debt issuance costs are charged to financing costs over the life of the related debt issuances. Discount amortization of $1 million, $2 million, and $6 million was recorded as interest expense in 2023, 2022, and 2021, respectively.

Uncommitted Lines of Credit

Apache from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2023 and 2022, there were no outstanding borrowings under these facilities. As of December 31, 2023, there were £296 million and $2 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

Unsecured 2022 Committed Bank Credit Facilities

On April 29, 2022, Apache entered into two unsecured guaranties of obligations under two unsecured syndicated credit agreements then entered into by APA Corporation (APA), of which Apache is a wholly owned subsidiary. APA’s new credit agreements are for general corporate purposes and replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One credit agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). APA may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to APA’s two, one-year extension options.

•The second credit agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to APA’s two, one-year extension options.

In connection with APA’s entry into the USD Agreement and the GBP Agreement (each, a 2022 Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under APA’s USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a 2022 Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under APA’s USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. As of December 31, 2023 and 2022, there were no borrowings by Apache outstanding under the USD Agreement. Apache has guaranteed obligations under each 2022 Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which require such support while Apache’s credit rating by Standard & Poor’s remains below BBB; on March 26, 2020, Standard & Poor’s reduced Apache’s rating from BBB to BB+, which was affirmed in 2023.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

All borrowings under the USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin ranging from 0.10% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.10% to 1.675% (Applicable Margin). All borrowings under the GBP Agreement bear interest at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average published by the Bank of England, plus the Applicable Margin. Each 2022 Agreement also requires the borrower to pay quarterly a facility fee on total commitments. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2023, Apache’s Long-Term Debt Rating applied, and the Base Rate Margin was 0.40%, the Applicable Margin was 1.40%, and the facility fee was 0.225%.

A commission is payable quarterly to lenders under each 2022 Agreement on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

Borrowers under each 2022 Agreement, which may include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default substantially similar to those in the Former Facility, such as:

•A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital continues to exclude the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2023, APA’s debt-to-capital ratio as calculated under each 2022 Agreement was 20 percent.

•A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $1.9 billion as of December 31, 2023.

•Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.

•Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.

Consistent with the Former Facility, the 2022 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.

Apache was in compliance with applicable terms of each 2022 Agreement as of December 31, 2023.

Commercial Paper Program

On December 13, 2023, APA established a commercial paper program under which APA may from time to time issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (the CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time.

The Company has unconditionally guaranteed payment of the CP Notes on an unsecured basis, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under the Company’s existing indentures is less than US$1.0 billion.

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The CP Notes will be sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance. The maturities of the CP Notes may vary but may not exceed 397 days from the date of issuance.

As of December 31, 2023, APA had not issued any CP Notes.

Subsequent Event

On January 30, 2024, Apache entered into an unsecured guaranty of obligations under an unsecured syndicated credit agreement then entered into by APA under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Credit Agreement). Apache’s guaranty is effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.

Subject to satisfaction of certain limited conditions, APA may borrow under the Credit Agreement to refinance certain indebtedness of Callon Petroleum Company, a Delaware corporation (Callon), upon or after closing of APA’s pending acquisition of Callon pursuant to the previously announced Agreement and Plan of Merger among APA, Astro Comet Merger Sub Corp., a Delaware corporation and wholly owned subsidiary of APA, and Callon, dated January 3, 2024 (Merger Agreement).

Two tranches of term loans would be available to APA for borrowing only on the date of closing of transactions under the Merger Agreement and satisfaction of certain other conditions under the Credit Agreement (Closing Date); of the aggregate $2.0 billion in commitments, $1.5 billion is for term loans that would mature three years after the Closing Date (3-Year Tranche Loans) and $500 million is for term loans that would mature 364 days after the Closing Date (364-Day Tranche Loans).

Indebtedness of Callon that APA could refinance by borrowing under the Credit Agreement on the Closing Date includes indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes, and together with the Callon Credit Agreement, Callon’s 2026 Notes, and Callon’s 2028 Notes, the Callon Indebtedness).

The Credit Agreement has limited conditions to funding on the Closing Date loans requested by APA in accordance with the Credit Agreement, such as consummation of the transactions under the Merger Agreement, no Company Material Adverse Effect (as defined in the Merger Agreement) has occurred, repayment of all indebtedness outstanding under the Callon Credit Agreement and Callon’s 2026 Notes, and Callon having no other material indebtedness for borrowed money except for Callon’s 2028 Notes and Callon’s 2030 Notes or as permitted under the Credit Agreement or the Merger Agreement.

Proceeds of loans made under the Credit Agreement may only be used to refinance the Callon Indebtedness and repay fees and expenses related to transactions under the Credit Agreement and the Merger Agreement. To the extent that borrowings by APA under the Credit Agreement are not so used on or before the date that is 120 days after the Closing Date, APA then must prepay the amount of such unused borrowings.

If $400 million or more in aggregate principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes remains outstanding on the date which is 120 days after the Closing Date, Callon then must guarantee APA’s obligations under the Credit Agreement effective until the aggregate outstanding principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes first is less than $400 million.

APA may at any time prepay loans under the Credit Agreement. APA may at any time terminate, or from time to time reduce, the lenders’ commitments under the Credit Agreement. Unless previously terminated, the lenders’ commitments automatically terminate on the first to occur of: (i) the Closing Date, after giving effect to funding of each lender’s commitments on the Closing Date, (ii) APA’s acquisition of Callon pursuant to the Merger Agreement without loans being made under the Credit Agreement, (iii) termination of the Merger Agreement in accordance with its terms, and (iv) the Termination Date (as defined in, and may be extended pursuant to, the Merger Agreement).

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

All borrowings under the Credit Agreement would be in U.S. Dollars and bear interest at one of the following two rate options, as selected by APA, plus the indicated margin:

•One option is a base rate per annum equal to the greatest of (i) the applicable prime rate, (ii) the greater of the applicable federal funds rate and overnight bank funding rate, plus 0.50%, and (iii) an adjusted secured overnight financing rate published by the Federal Reserve Bank of New York (SOFR) for a one-month interest period plus 1.0%. The margin for this rate option (Term Base Rate Margin) is a rate per annum varying from 0.25% to 1.0% for 364-Day Tranche Loans, 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, in each case, based on the rating for senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache. Apache’s Long-Term Debt Rating currently applies.

•The second option is an adjusted SOFR rate, plus a margin at a rate per annum varying from 1.25% to 2.0% for 364-Day Tranche Loans, 1.375% to 2.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 1.625% to 2.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, in each case, based on the Long-Term Debt Rating (Term Applicable Margin). For SOFR-based interest rates, APA may select an interest period of one, three, or six months.

Currently, the Term Base Rate Margin is 0.625% for 364-Day Tranche Loans and 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin is 1.625% for 364-Day Tranche Loans and 1.75% for 3-Year Tranche Loans.

The Credit Agreement provides for a ticking fee payable by APA at a rate of 0.225% per annum on the daily average undrawn aggregate commitments thereunder; the ticking fee accrues during the period beginning on the date that is 90 days after January 3, 2024 to the earlier of (i) termination or expiration of the commitments or (ii) the Closing Date.

APA is subject to representations and warranties, covenants, and events of default under the Credit Agreement substantially similar to those in APA’s existing 2022 Agreements. The Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings.

11. INCOME TAXES

Net income before income taxes was composed of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
U.S.	$	594	$	2,656	$	689
Foreign	2,322		3,218		1,291
Total	$	2,916	$	5,874	$	1,980

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The total income tax provision (benefit) consisted of the following:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Current income taxes:
Federal	$	2	$	1	$	16
State	6		11		—
Foreign	1,330		1,495		636
	1,338		1,507		652
Deferred income taxes:
Federal	(1,696)		—		—
State	(34)		—		—
Foreign	78		145		(74)
	(1,652)		145		(74)
Total	$	(314)	$	1,652	$	578

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Income tax expense at U.S. statutory rate	$	612	$	1,234	$	416
State income tax, less federal effect(1)	(25)		9		—
Taxes related to foreign operations	753		774		300
Tax credits	—		(4)		(10)






Net change in tax contingencies	5		1		16


Valuation allowances(1)	(1,838)		(705)		(111)
Tax adjustments attributable to BCP Business Combination	—		126		—
Remeasurement of U.K. deferred tax liability	174		208		—
Tax attributable to Altus Preferred Unit limited partners	—		—		(34)
All other, net	5		9		1
	$	(314)	$	1,652	$	578

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

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	2023		2022

	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,027	$	2,035
Capital losses	8		357

Tax credits and other tax incentives	26		26
Foreign tax credits	2,204		2,241
Accrued expenses and liabilities	130		145
Asset retirement obligation	849		672

Equity investments	8		—
Net interest expense limitation	74		55
Lease liability	71		113
Decommissioning contingency for sold Gulf of Mexico properties	210		275

Total deferred tax assets	5,607		5,919
Valuation allowance	(2,549)		(4,831)
Net deferred tax assets	3,058		1,088
Deferred tax liabilities:


Equity investments	—		1

Property and equipment	1,510		1,014
Right-of-use asset	69		110
Decommissioning security for sold Gulf of Mexico properties	44		148
Other	59		90
Total deferred tax liabilities	1,682		1,363
Net deferred income tax (asset) liability	$	(1,376)	$	275

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


	2023		2022

	(In millions)
Assets:
Other assets
Deferred tax asset	$	1,747	$	39
Liabilities:
Deferred credits and other noncurrent liabilities
Deferred tax liability	371		314
Net deferred income tax (asset) liability	$	(1,376)	$	275

On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded a deferred tax expense of $208 million and $174 million related to the remeasurement of the U.K. deferred tax liability in 2022 and 2023, respectively.

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On January 14, 2022, Apache Midstream LLC, a wholly owned subsidiary of Apache, exchanged 12.5 million Common Units in Altus Midstream LP for 12.5 million shares of ALTM Class A Common Stock, in a taxable exchange. On February 22, 2022, as a result of the BCP Business Combination, the Company deconsolidated ALTM. On March 11, 2022, the Company sold four million of its Kinetik Shares. The Company recorded tax expense of $126 million associated with the BCP Business Combination. The tax impact of the BCP Business Combination was fully offset by a change in valuation allowance. Refer to Note 3— Acquisitions and Divestitures for further detail.

The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. The Company showed positive income over the three-year period ended December 31, 2023. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence (such as a cumulative loss in recent years), the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. The remaining U.S. valuation allowance relates primarily to foreign tax credit and capital loss carryforwards.

In 2023, 2022, and 2021, the Company’s valuation allowance decreased by $2.3 billion, $1.0 billion, and $116 million, respectively, as detailed in the table below:


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	4,831	$	5,875	$	5,991
State(1)	(61)		(111)		1
U.S.	(2,221)		(706)		(112)
Foreign	—		(227)		(5)

Balance at end of year	$	2,549	$	4,831	$	5,875

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

On December 31, 2023, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

7,922

2027 - Indefinite

State

6,541

Various

The Company has a U.S. net operating loss carryforward of $7.9 billion, which includes $107 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $6.5 billion, and a net interest expense carryover of $345 million under Section 163(j) of the Code with indefinite carryover. In 2023, $1.7 billion of U.S. capital loss carryforward expired unutilized with $34 million remaining, which has a five year carryover period expiring in 2027. The Company has recorded a valuation allowance against some of the U.S. net operating losses, a majority of the state net operating losses, the foreign net operating losses, and the U.S. capital loss because it is more likely than not that these net operating losses and the capital loss carryforward will not be realized. The Company believes it is more likely than not that the deferred tax assets related to the remaining U.S. and state net operating losses, and the net interest expense carryover will be utilized prior to their expiration.

On December 31, 2023, the Company had foreign tax credits as follows:


	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,204	2025-2026

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

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	2023		2022		2021

	(In millions)
Balance at beginning of year	$	89	$	116	$	93
Additions based on tax positions related to prior year	4		—		16
Additions based on tax positions related to the current year	—		—		7
Reductions for tax positions of prior years	(8)		(27)		—
Balance at end of year	$	85	$	89	$	116

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2023, 2022, and 2021, the Company recorded tax expense of $2 million, $1 million, and $1 million, respectively, for interest and penalties. At December 31, 2023, 2022, and 2021, the Company had an accrued liability for interest and penalties of $7 million, $5 million, and $4 million, respectively.

In 2023, 2022, and 2021, the Company recorded a $4 million net decrease, a $27 million net decrease, and a $23 million net increase, respectively, in its reserve for uncertain tax positions.

On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice.

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

Jurisdiction


U.S.			2014
Egypt			2005
U.K.			2022

12. COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of December 31, 2023, the Company has an accrued liability of approximately $83 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Argentine Environmental Claims

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

Louisiana Restoration

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

Starting in November of 2013 and continuing into 2023, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, the Company agreed to settle with the State of Louisiana and Louisiana coastal Parishes to resolve any potential liability on the part of the Company for claims that were or could have been asserted by the coastal Parishes and/or the State of Louisiana in the pending litigation. The settlement is subject to court approval, which the parties hope to receive at some point in the first half of 2024. The consideration to be provided by the Company in the settlement will not have a material impact on the Company’s financial position. Following settlement of these various lawsuits, the Company will be a defendant in only one remaining coastal zone lawsuit, which has been filed by the City of New Orleans against a number of oil and gas operators.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiffs’ claims. The Texas Supreme Court granted the Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of appeals’ decision and remanded the case back to the court of appeals for further proceedings. After plaintiffs’ request for rehearing, on July 21, 2023, the Texas Supreme Court reaffirmed its reversal of the court of appeals’ decision and remand of the case back to the court of appeals for further proceedings.

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company will vigorously prosecute its claim while vigorously defending against Quadrant’s counter claims.

Canadian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Flesch class action matter under which Apache will pay $7 million USD to resolve all claims against the Company asserted by the class. The settlement was approved by the court on October 26, 2023.

California and Delaware Litigation

On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit.

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

The Company intends to challenge personal jurisdiction in California and to vigorously defend the Delaware lawsuit.

Kulp Minerals Lawsuit

On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.

Shareholder and Derivative Lawsuits

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

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on July 21, 2023, a case captioned Yang-Li-Yu, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. These cases have now been consolidated as In Re APA Corporation Derivative Litigation, Case No. 4:23-cv-00636 in the Southern District of Texas and purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants intend to vigorously defend these lawsuits.

Environmental Matters

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

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

As of December 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $5 million.

On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. Then on December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notices and information requests involved alleged emissions control and reporting violations. The Company cooperated with the EPA, responded to the information requests, and negotiated and entered into a consent decree to resolve the alleged violations in both New Mexico and Texas, which will be subject to court approval. The consideration to be provided by the Company in connection with the consent decree will not have a material impact on the Company’s financial position.

The Company is not aware of any environmental claims existing as of December 31, 2023, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Leases and Contractual Obligations

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

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $167 million, $144 million, and $127 million for the years ended 2023, 2022, and 2021, respectively. As allowed under the standard, Apache accounts for non-lease and lease components as a single lease component for all asset classes and has elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases, which are primarily related to decommissioning activities in the Gulf of Mexico, were $71 million in 2023 and not significant in 2022 and 2021.

Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million in each of the years 2023, 2022, and 2021. Interest on the Company’s finance lease liability was $1 million, $2 million, and $2 million in 2023, 2022, and 2021, respectively.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2023:


	Operating Leases		Finance Lease
Weighted average remaining lease term	6.9 years		9.7 years
Weighted average discount rate	5.3	%	4.4	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

At December 31, 2023, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)(5)

	(In millions)
2024	$	115	$	3	$	250
2025	35		3		197
2026	21		4		766
2027	23		4		143
2028	22		4		141
Thereafter	129		23		208
Total future minimum payments	345		41		$	1,705
Less: imputed interest	(65)		(9)		N/A
Total lease liabilities	280		32		N/A
Current portion	115		2		N/A
Non-current portion	$	165	$	30	N/A

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

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

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

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $182 million, $183 million, and $194 million in 2023, 2022, and 2021, respectively.

(5)Under terms agreed to in the Egypt merged concession agreement entered into in 2021, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2023, the Company has spent $2.9 billion and believes it will be able to satisfy the remaining obligation within its current exploration and development program.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $74 million, $89 million, and $63 million in 2023, 2022, and 2021, respectively.

13. RETIREMENT AND DEFERRED COMPENSATION PLANS

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

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

The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $44 million, $40 million, and $31 million for 2023, 2022, and 2021, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

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

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2023, 2022, and 2021, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	108		$	15		$	211		$	20		$	233		$	20
Service cost	1			1			2			1			3			1
Interest cost	5			1			3			—			3			—
Foreign currency exchange rates	6			—			(21)			—			(2)			—
Actuarial losses (gains)	3			—			(79)			(5)			(5)			1
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(3)			(4)			(4)
Retiree contributions	—			1			—			2			—			2
Projected benefit obligation at end of year	118			15			108			15			211			20
Change in Plan Assets
Fair value of plan assets at beginning of year	137			—			254			—			262			—
Actual return (loss) on plan assets	8			—			(87)			—			11			—
Foreign currency exchange rates	8			—			(26)			—			(3)			—
Employer contributions	2			1			4			2			5			2
Plan settlements	—			—			—			—			(17)			—
Benefits paid	(5)			(3)			(8)			(4)			(4)			(4)
Retiree contributions	—			2			—			2			—			2
Fair value of plan assets at end of year	150			—			137			—			254			—
Funded status at end of year	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	32			(13)			29			(13)			43			(18)
	$	32		$	(15)		$	29		$	(15)		$	43		$	(20)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(12)		$	16		$	(10)		$	18		$	1		$	14

Weighted Average Assumptions used as of December 31
Discount rate	4.80		%	5.00		%	5.00		%	5.29		%	1.80		%	2.57		%
Salary increases	4.60		%	N/A			4.70		%	N/A			4.90		%	N/A
Expected return on assets	4.80		%	N/A			4.70		%	N/A			1.90		%	N/A
Healthcare cost trend
Initial	N/A			6.25		%	N/A			6.50		%	N/A			6.25		%
Ultimate in 2030	N/A			5.25		%	N/A			5.25		%	N/A			5.00		%

F-40

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2023, 2022, and 2021, the accumulated benefit obligation for the U.K. Pension Plan was $112 million, $89 million, and $205 million, respectively.

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


	Percentage of Plan Assets at Year-End
	2023		2022
Asset Category
Global equities	—	%	6	%
Multi-asset credit	59	%	40	%
Nominal bonds	6	%	24	%
Inflation-linked bonds	33	%	28	%
Cash	2	%	2	%
Total	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2023 and 2022 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2023 and 2022:


	December 31,
	2023		2022

	(In millions)
Asset Category
Global equities	$	—	$	9
Multi-asset credit	88		55
Nominal bonds	9		32
Inflation-linked bonds	50		39
Cash	3		2
Total	$	150	$	137

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2023, 2022, and 2021:


	2023						2022						2021
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	1		$	1		$	2		$	1		$	3		$	1
Interest cost	5			1			3			—			3			—
Expected return on assets	(7)			—			(4)			—			(4)			—
Amortization of loss	—			(2)			—			(1)			—			(1)
Settlement loss	—			—			—			—			—			—
Net periodic benefit cost	$	(1)		$	—		$	1		$	—		$	2		$	—
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.00		%	5.29		%	1.80		%	2.57		%	1.40		%	2.06		%
Salary increases	4.70		%	N/A			4.90		%	N/A			4.50		%	N/A
Expected return on assets	4.70		%	N/A			1.90		%	N/A			1.50		%	N/A
Healthcare cost trend
Initial	N/A			6.50		%	N/A			6.25		%	N/A			6.00		%
Ultimate in 2030	N/A			5.25		%	N/A			5.00		%	N/A			5.00		%

The Company expects to contribute approximately $2 million to its pension plan and $2 million to its postretirement benefit plan in 2024. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits

	(In millions)
2024	$	5	$	2
2025	5		2
2026	5		1
2027	6		1
2028	6		1
Years 2029-2033	34		6

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. REDEEMABLE NONCONTROLLING INTEREST — ALTUS

Preferred Units Issuance

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

Classification

Prior to the deconsolidation of Altus on February 22, 2022, at December 31, 2021, the carrying amount of the Preferred Units was recorded as “Redeemable Noncontrolling Interest — Altus Preferred Unit Limited Partners” and classified as temporary equity on the Company’s consolidated balance sheet based on the terms of the Preferred Units, including the redemption rights with respect thereto.

Measurement

Altus applied a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end was recorded, if applicable. The amount of such adjustment was determined based upon the accreted value method to reflect the passage of time until the Preferred Units were exchangeable at the option of the holder. Accordingly, prior to the deconsolidation of Altus on February 22, 2022, the Company recorded a net loss attributable to Altus Preferred Unit limited partners totaling $70 million and net income attributable to Altus Preferred Unit limited partners totaling $162 million during 2022 and 2021, respectively.

15. CAPITAL STOCK AND EQUITY

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

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

Net Income (Loss) per Common Share

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

Stock Compensation Plans

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2023, 9.4 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in APA’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	27	$	82	$	39
Exploration	4		13		5
General and administrative	50		193		108
Total stock-settled and cash-settled compensation expensed	81		288		152
Stock-settled and cash-settled compensation capitalized	13		43		18
Total stock-settled and cash-settled compensation costs	$	94	$	331	$	170

Stock Options

As of December 31, 2023, APA had outstanding options to purchase shares of APA’s common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

The following table summarizes stock option activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	2,078	$	57.71	3,012	$	63.79	3,537	$	72.10

Exercised	(12)	42.38		(99)	42.09		—	—
Forfeited	—	—		(2)	49.10		—	—
Expired	(601)	80.53		(833)	81.56		(525)	119.83
Outstanding, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79
Expected to vest	—	—		—	—		—	—
Exercisable, end of year(1)	1,465	48.48		2,078	57.71		3,012	63.79

(1)As of December 31, 2023, options exercisable and outstanding had a weighted average remaining contractual life of 3.1 years and aggregate intrinsic value of $33,000.

During the years ended December 31, 2023, 2022, and 2021, there were no options issued and 12,183, 98,646, and no options, respectively, exercised.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Restricted Stock Units and Restricted Stock Phantom Units

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

For the years ended December 31, 2023, 2022, and 2021, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $70 million, $145 million, and $91 million, respectively. As of December 31, 2023, 2022, and 2021, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $11 million, $22 million, and $15 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2023, 2022, and 2021:


	2023			2022			2021
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,885	$	23.08	2,073	$	19.98	1,552	$	28.43
Granted	661	41.60		847	29.90		1,506	16.46
Vested(3)	(975)	23.31		(978)	22.39		(857)	29.13
Forfeited	(69)	32.44		(57)	23.49		(128)	19.78
Expired	(22)	27.81		—	—		—	—
Non-vested, end of year(1)(2)	1,480	30.69		1,885	23.08		2,073	19.98

(1)As of December 31, 2023, there was $15 million of total unrecognized compensation cost related to 1,479,880 unvested stock-settled restricted stock units.

(2)As of December 31, 2023, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.6 years.

(3)The grant date fair values of the stock-settled awards vested during 2023, 2022, and 2021 were approximately $23 million, $22 million, and $25 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	5,709	6,402	4,423

Adjustment from ALTM transaction(1)	—	143	—
Granted(2)	1,972	2,568	4,441
Vested	(2,851)	(2,970)	(2,049)
Forfeited	(340)	(434)	(413)
Expired	(12)	—	—
Non-vested, end of year(3)	4,478	5,709	6,402

(1)Following the BCP Business Combination, certain employees were granted restricted stock phantom units based on APA’s common stock price to replace the equivalent value in restricted stock phantom units based on ALTM’s common stock price.

(2)Restricted stock phantom units granted during 2023, 2022, and 2021 included 1,972,116, 2,512,602, and 4,375,546 awards, respectively, based on the per-share market price of APA common stock. Restricted stock phantom units granted during 2022 and 2021 included 55,546 and 65,327 awards, respectively, based on the per-share market price of ALTM common stock prior to the deconsolidation of Altus on February 22, 2022.

(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2023 was approximately $54 million.

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In January 2024, APA awarded 819,836 restricted stock units and 2,356,255 restricted stock phantom units based on APA’s weighted-average per-share market price of $33.73 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $28 million and $80 million, respectively, and was calculated based on the per-share fair market value of a share of APA’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, APA makes annual grants of cash-settled conditional restricted stock phantom units to eligible employees. APA has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2023, are as described below:

•In January 2020, APA’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. A total of 999,896 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 155 percent of target.

•In January 2021, APA’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. A total of 1,803,083 phantom units were outstanding as of December 31, 2023. The results for the performance period yielded a payout of 118 percent of target.

•In January 2022, APA’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 1,040,100 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 2,080,200 units could be awarded.

•In January 2023, APA’s Board of Directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 822,200 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 784,977 phantom units were outstanding as of December 31, 2023, from which a minimum of zero to a maximum of 1,569,954 units could be awarded.

Compensation expense related to the conditional cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the cash-settled performance programs were expenses of $2 million, $136 million, and $56 million during 2023, 2022, and 2021, respectively. Capitalized compensation costs under the cash-settled performance programs were expenses of approximately $100 thousand, $21 million, and $3 million during 2023, 2022, and 2021, respectively.

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2023, 2022, and 2021:


	For the Year Ended December 31,
	2023	2022	2021

	(In thousands)
Non-vested, beginning of year	4,835	4,531	3,417
Granted	1,536	1,676	1,782
Vested	(1,593)	(656)	(76)
Forfeited	(99)	(106)	(240)
Expired	(50)	(610)	(352)
Non-vested, end of year(1)	4,629	4,835	4,531

(1)As of December 31, 2023, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $24 million.

In January 2024, APA’s Board of Directors approved the 2024 Performance Program, pursuant to the 2016 Plan. A portion of the award is based upon measurement of TSR similar to prior year awards, and the remaining portion of the award is based on performance and financial objectives as defined in the 2024 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 644,399 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,288,798 units. These phantom units represent a hypothetical interest in APA’s common stock and once vested, are settled in cash. These phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of APA’s common stock, a Level 1 fair value measurement. The cash incentives totaled $14 million, with the ultimate payout ranging from zero to $28 million. Final payout of the awards will be determined at the end of a three-year performance period.

16. ACCUMULATED OTHER COMPREHENSIVE INCOME

Components of accumulated other comprehensive income include the following:


	As of December 31,
	2023		2022		2021

	(In millions)

Pension and postretirement benefit plan (Note 13)	$	15	$	14	$	22
Accumulated other comprehensive income	$	15	$	14	$	22

17. MAJOR CUSTOMERS

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

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18. BUSINESS SEGMENT INFORMATION

As of December 31, 2023, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. Prior to the deconsolidation of Altus on February 22, 2022, the Company’s Midstream business was operated by ALTM, which owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2023
Oil revenues	$	2,683	$	1,073	$	2,003	$	—	$	—	$	5,759
Natural gas revenues	346		237		277		—		—		860
Natural gas liquids revenues	—		28		432		—		—		460
Oil, natural gas, and natural gas liquids production revenues	3,029		1,338		2,712		—		—		7,079
Purchased oil and gas sales	—		—		894		—		—		894

	3,029		1,338		3,606		—		—		7,973
Operating Expenses:
Lease operating expenses	474		369		554		—		—		1,397
Gathering, processing, and transmission	33		52		229		—		—		314
Purchased oil and gas costs	—		—		742		—		—		742
Taxes other than income	—		—		192		—		—		192
Exploration	119		19		14		—		1		153
Depreciation, depletion, and amortization	524		271		604		—		—		1,399
Asset retirement obligation accretion	—		76		40		—		—		116
Impairments	—		50		11		—		—		61
	1,150		837		2,386		—		1		4,374
Operating Income (Loss)	$	1,879	$	501	$	1,220	$	—	$	(1)	3,599
Other Income (Expense):
Gain on divestitures, net											8
Losses on previously sold Gulf of Mexico properties											(212)

Other											26
General and administrative											(325)
Transaction, reorganization, and separation											(15)
Financing costs, net											(165)
Income Before Income Taxes											$	2,916

Total Assets(3)	$	3,503	$	1,970	$	11,471	$	—	$	—	$	16,944
Net Property and Equipment	$	2,209	$	1,628	$	4,887	$	—	$	—	$	8,724
Additions to Net Property and Equipment	$	834	$	131	$	946	$	—	$	—	$	1,911

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2022
Oil revenues	$	3,145	$	1,232	$	2,323	$	—	$	—	$	6,700
Natural gas revenues	370		281		894		—		—		1,545
Natural gas liquids revenues	6		45		735		—		(3)		783
Oil, natural gas, and natural gas liquids production revenues	3,521		1,558		3,952		—		(3)		9,028
Purchased oil and gas sales	—		—		1,850		5		—		1,855
Midstream service affiliate revenues	—		—		—		16		(16)		—
	3,521		1,558		5,802		21		(19)		10,883
Operating Expenses:
Lease operating expenses	526		404		506		—		(1)		1,435
Gathering, processing, and transmission	22		43		304		5		(18)		356
Purchased oil and gas costs	—		—		1,776		—		—		1,776
Taxes other than income	—		—		253		3		—		256
Exploration	84		35		24		—		3		146
Depreciation, depletion, and amortization	400		238		537		2		—		1,177
Asset retirement obligation accretion	—		82		34		1		—		117

	1,032		802		3,434		11		(16)		5,263
Operating Income (Loss)	$	2,489	$	756	$	2,368	$	10	$	(3)	5,620
Other Income (Expense):
Gain on divestitures, net											1,180
Losses on previously sold Gulf of Mexico properties											(157)
Derivative instrument losses, net											(107)
Other											139
General and administrative											(462)
Transaction, reorganization, and separation											(26)
Financing costs, net											(313)
Income Before Income Taxes											$	5,874

Total Assets(3)	$	3,148	$	1,911	$	9,196	$	—	$	—	$	14,255
Net Property and Equipment	$	1,976	$	1,386	$	4,595	$	—	$	—	$	7,957
Additions to Net Property and Equipment	$	695	$	210	$	752	$	—	$	—	$	1,657

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Egypt(1)		North Sea		U.S.		Altus Midstream		Intersegment Eliminations & Other		Total(2)
	Upstream

	(In millions)
2021
Oil revenues	$	1,806	$	929	$	1,850	$	—	$	—	$	4,585
Natural gas revenues	270		183		754		—		—		1,207
Natural gas liquids revenues	9		24		676		—		(3)		706
Oil, natural gas, and natural gas liquids production revenues	2,085		1,136		3,280		—		(3)		6,498
Purchased oil and gas sales	—		—		1,476		11		—		1,487
Midstream service affiliate revenues	—		—		—		127		(127)		—
	2,085		1,136		4,756		138		(130)		7,985
Operating Expenses:
Lease operating expenses	469		383		391		—		(2)		1,241
Gathering, processing, and transmission	12		39		309		32		(128)		264
Purchased oil and gas costs	—		—		1,575		5		—		1,580
Taxes other than income	—		—		190		14		—		204
Exploration	63		34		28		—		2		127
Depreciation, depletion, and amortization	524		270		554		12		—		1,360
Asset retirement obligation accretion	—		79		30		4		—		113
Impairments	26		22		—		160		—		208
	1,094		827		3,077		227		(128)		5,097
Operating Income (Loss)	$	991	$	309	$	1,679	$	(89)	$	(2)	2,888
Other Income (Expense):
Gain on divestitures, net											67
Losses on previously sold Gulf of Mexico properties											(446)
Derivative instrument gains, net											94
Other											228
General and administrative											(357)
Transaction, reorganization, and separation											(22)
Financing costs, net											(472)
Income Before Income Taxes											$	1,980

Total Assets(3)	$	2,796	$	2,199	$	7,700	$	1,698	$	—	$	14,393
Net Property and Equipment	$	1,720	$	1,646	$	4,507	$	187	$	—	$	8,060
Additions to Net Property and Equipment	$	319	$	159	$	523	$	3	$	—	$	1,004

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2023, 2022, and 2021 of:


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Oil	$	729	$	989	$	420
Natural gas	95		117		47
Natural gas liquids	—		2		2

(2)Includes noncontrolling interests in Egypt for all periods presented and a noncontrolling interest in Altus Midstream for the years 2022 and 2021.

(3)Intercompany balances are excluded from total assets.

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

19. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

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


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions, except per boe)
2023
Oil and gas production revenues	$	2,712	$	3,029	$	1,338	$	—	$	7,079
Operating cost:
Depreciation, depletion, and amortization(2)	568		521		270		—		1,359
Asset retirement obligation accretion	40		—		76		—		116
Lease operating expenses	554		474		369		—		1,397
Gathering, processing, and transmission	229		33		52		—		314
Exploration expenses	14		119		19		1		153

Production taxes(3)	189		—		—		—		189
Income tax	235		828		414		—		1,477
	1,829		1,975		1,200		1		5,005
Results of operations	$	883	$	1,054	$	138	$	(1)	$	2,074
2022
Oil and gas production revenues	$	3,952	$	3,521	$	1,558	$	—	$	9,031
Operating cost:
Depreciation, depletion, and amortization(2)	508		390		232		—		1,130
Asset retirement obligation accretion	34		—		82		—		116
Lease operating expenses	506		526		404		—		1,436
Gathering, processing, and transmission	304		22		43		—		369
Exploration expenses	24		84		35		3		146

Production taxes(3)	252		—		—		—		252
Income tax	488		1,100		495		—		2,083
	2,116		2,122		1,291		3		5,532
Results of operations	$	1,836	$	1,399	$	267	$	(3)	$	3,499
2021
Oil and gas production revenues	$	3,280	$	2,085	$	1,136	$	—	$	6,501
Operating cost:
Depreciation, depletion, and amortization(2)	511		477		267		—		1,255
Asset retirement obligation accretion	30		—		79		—		109
Lease operating expenses	391		469		383		—		1,243
Gathering, processing, and transmission	309		12		39		—		360
Exploration expenses	28		63		34		2		127

Production taxes(3)	188		—		—		—		188
Income tax	383		479		134		—		996
	1,840		1,500		936		2		4,278
Results of operations	$	1,440	$	585	$	200	$	(2)	$	2,223

(1)Includes noncontrolling interests in Egypt.

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

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

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	United States		Egypt(2)		North Sea		Other International		Total(2)

	(In millions)
2023
Acquisitions:
Proved	$	—	$	4	$	—	$	—	$	4
Unproved	19		—		—		—		19
Exploration	5		226		44		1		276
Development	864		646		468		—		1,978
Costs incurred(1)	$	888	$	876	$	512	$	1	$	2,277
(1) Includes asset retirement costs:

Asset retirement costs	$	(7)	$	—	$	375	$	—	$	368
2022
Acquisitions:
Proved	$	19	$	3	$	—	$	—	$	22
Unproved	28		—		—		—		28
Exploration	4		169		61		3		237
Development	775		568		(57)		—		1,286
Costs incurred(1)	$	826	$	740	$	4	$	3	$	1,573
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	—	$	—	$	1	$	—	$	1
Asset retirement costs	76		—		(215)		—		(139)

2021
Acquisitions:
Proved	$	—	$	(157)	$	—	$	—	$	(157)
Unproved	9		20		—		—		29
Exploration	6		86		39		30		161
Development	545		404		135		1		1,085
Costs incurred(1)	$	560	$	353	$	174	$	31	$	1,118
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	—	$	—
Asset retirement costs	130		—		19		—		149
Egypt PSC modernization impacts – Proved and Unproved	—		(145)		—		—		(145)
(2) Includes noncontrolling interests in Egypt.

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

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Capitalized Costs

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


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions)
2023
Proved properties	$	19,809	$	13,777	$	9,472	$	—	$	43,058
Unproved properties	217		71		3		—		291
	20,026		13,848		9,475		—		43,349
Accumulated DD&A	(15,390)		(11,678)		(7,849)		—		(34,917)
	$	4,636	$	2,170	$	1,626	$	—	$	8,432

2022
Proved properties	$	18,990	$	13,014	$	8,945	$	—	$	40,949
Unproved properties	208		77		11		—		296
	19,198		13,091		8,956		—		41,245
Accumulated DD&A	(14,846)		(11,157)		(7,573)		—		(33,576)
	$	4,352	$	1,934	$	1,383	$	—	$	7,669

(1)Includes noncontrolling interests in Egypt.

Oil and Gas Reserve Information

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

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	206,936	95,981	86,566	389,483
December 31, 2021	180,968	106,646	77,073	364,687
December 31, 2022	168,817	108,050	82,580	359,447
December 31, 2023	167,911	102,305	61,076	331,292
Proved undeveloped reserves:
December 31, 2020	25,516	11,228	7,273	44,017
December 31, 2021	18,168	11,003	5,757	34,928
December 31, 2022	16,221	8,557	2,873	27,651
December 31, 2023	29,012	5,254	—	34,266

Total proved reserves:
Balance December 31, 2020	232,452	107,209	93,839	433,500
Extensions, discoveries and other additions	17,869	13,390	2,288	33,547
Purchases of minerals in-place	126	—	—	126
Revisions of previous estimates	(4,479)	22,727	(60)	18,188
Production	(27,450)	(25,677)	(13,237)	(66,364)
Sales of minerals in-place	(19,382)	—	—	(19,382)
Balance December 31, 2021	199,136	117,649	82,830	399,615
Extensions, discoveries and other additions	9,776	7,580	2,616	19,972
Purchases of minerals in-place	522	—	—	522
Revisions of previous estimates	7,170	22,433	11,898	41,501
Production	(24,141)	(31,055)	(11,891)	(67,087)
Sales of minerals in-place	(7,425)	—	—	(7,425)
Balance December 31, 2022	185,038	116,607	85,453	387,098
Extensions, discoveries and other additions	37,353	12,979	301	50,633

Revisions of previous estimates	1,062	10,505	(12,002)	(435)
Production	(25,755)	(32,532)	(12,676)	(70,963)
Sales of minerals in-place	(775)	—	—	(775)
Balance December 31, 2023	196,923	107,559	61,076	365,558

(1)Includes proved reserves of 53 MMbbls, 62 MMbbls, 39 MMbbls, and 36 MMbbls as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Natural Gas Liquids
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2020	150,599	716	2,053	153,368
December 31, 2021	164,172	446	2,059	166,677
December 31, 2022	152,999	—	2,230	155,229
December 31, 2023	145,618	—	1,460	147,078
Proved undeveloped reserves:
December 31, 2020	15,141	126	320	15,587
December 31, 2021	16,380	30	275	16,685
December 31, 2022	15,398	—	76	15,474
December 31, 2023	16,413	—	—	16,413

Total proved reserves:
Balance December 31, 2020	165,740	842	2,373	168,955
Extensions, discoveries and other additions	21,055	7	81	21,143
Purchases of minerals in-place	191	—	—	191
Revisions of previous estimates	22,724	(180)	318	22,862
Production	(24,175)	(193)	(438)	(24,806)
Sales of minerals in-place	(4,983)	—	—	(4,983)
Balance December 31, 2021	180,552	476	2,334	183,362
Extensions, discoveries and other additions	5,456	—	45	5,501
Purchases of minerals in-place	233	—	—	233
Revisions of previous estimates	10,355	(407)	333	10,281
Production	(21,859)	(69)	(406)	(22,334)
Sales of minerals in-place	(6,340)	—	—	(6,340)
Balance December 31, 2022	168,397	—	2,306	170,703
Extensions, discoveries and other additions	20,827	—	371	21,198

Revisions of previous estimates	(6,343)	—	(764)	(7,107)
Production	(20,817)	—	(453)	(21,270)
Sales of minerals in-place	(33)	—	—	(33)
Balance December 31, 2023	162,031	—	1,460	163,491

(1) Includes proved reserves of 159 Mbbls and 281 Mbbls as of December 31, 2021 and 2020, respectively, attributable to noncontrolling interests in Egypt.

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)

	(Millions of cubic feet)
Proved developed reserves:
December 31, 2020	1,052,756	409,035	68,159	1,529,950
December 31, 2021	1,237,461	464,826	76,155	1,778,442
December 31, 2022	1,128,066	399,502	66,292	1,593,860
December 31, 2023	953,578	377,144	46,839	1,377,561
Proved undeveloped reserves:
December 31, 2020	76,504	12,572	8,341	97,417
December 31, 2021	184,441	9,899	7,124	201,464
December 31, 2022	188,976	1,068	2,304	192,348
December 31, 2023	86,800	2,612	—	89,412

Total proved reserves:
Balance December 31, 2020	1,129,260	421,607	76,500	1,627,367
Extensions, discoveries and other additions	227,684	50,209	3,684	281,577
Purchases of minerals in-place	839	—	—	839
Revisions of previous estimates	279,610	99,143	17,171	395,924
Production	(192,523)	(96,234)	(14,076)	(302,833)
Sales of minerals in-place	(22,968)	—	—	(22,968)
Balance December 31, 2021	1,421,902	474,725	83,279	1,979,906
Extensions, discoveries and other additions	38,157	10,191	1,643	49,991
Purchases of minerals in-place	1,592	—	—	1,592
Revisions of previous estimates	96,381	45,725	(3,431)	138,675
Production	(167,580)	(130,071)	(12,895)	(310,546)
Sales of minerals in-place	(73,410)	—	—	(73,410)
Balance December 31, 2022	1,317,042	400,570	68,596	1,786,208
Extensions, discoveries and other additions	125,654	14,188	3,335	143,177

Revisions of previous estimates	(249,257)	83,907	(6,739)	(172,089)
Production	(152,925)	(118,909)	(18,353)	(290,187)
Sales of minerals in-place	(136)	—	—	(136)
Balance December 31, 2023	1,040,378	379,756	46,839	1,466,973

(1) Includes proved reserves of 188 Bcf, 224 Bcf, 158 Bcf, and 141 Bcf as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt.

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Total(1)

	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2020	532,994	164,870	99,979	797,843
December 31, 2021	551,384	184,563	91,825	827,772
December 31, 2022	509,827	174,633	95,859	780,319
December 31, 2023	472,459	165,162	70,343	707,964
Proved undeveloped reserves:
December 31, 2020	53,408	13,449	8,983	75,840
December 31, 2021	65,288	12,683	7,219	85,190
December 31, 2022	63,115	8,735	3,333	75,183
December 31, 2023	59,891	5,690	—	65,581

Total proved reserves:
Balance December 31, 2020	586,402	178,319	108,962	873,683
Extensions, discoveries and other additions	76,871	21,765	2,983	101,619
Purchases of minerals in-place	457	—	—	457
Revisions of previous estimates	64,847	39,071	3,120	107,038
Production	(83,712)	(41,909)	(16,021)	(141,642)
Sales of minerals in-place	(28,193)	—	—	(28,193)
Balance December 31, 2021	616,672	197,246	99,044	912,962
Extensions, discoveries and other additions	21,592	9,278	2,935	33,805
Purchases of minerals in-place	1,020	—	—	1,020
Revisions of previous estimates	33,588	29,647	11,659	74,894
Production	(73,930)	(52,803)	(14,446)	(141,179)
Sales of minerals in-place	(26,000)	—	—	(26,000)
Balance December 31, 2022	572,942	183,368	99,192	855,502
Extensions, discoveries and other additions	79,123	15,344	1,228	95,695

Revisions of previous estimates	(46,824)	24,490	(13,889)	(36,223)
Production	(72,060)	(52,350)	(16,188)	(140,598)
Sales of minerals in-place	(831)	—	—	(831)
Balance December 31, 2023	532,350	170,852	70,343	773,545

(1) Includes total proved reserves of 84 MMboe, 99 MMboe, 66 MMboe, and 59 MMboe as of December 31, 2023, 2022, 2021, and 2020, respectively, attributable to noncontrolling interests in Egypt.

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2022, the Company added approximately 34 MMboe from extensions, discoveries, and other additions. The Company recorded 22 MMboe of exploration and development adds in the U.S., comprising 9 MMboe in the Permian Basin, 8 MMboe in the Texas Gulf Coast, and 5 MMboe in the Delaware Basin. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 12 MMboe of exploration and development adds, with Egypt contributing 9 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 3 MMboe from the North Sea. The Company had combined upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with Egypt accounting for an increase of 43 MMboe, primarily the result of PSC modernization in Egypt. The North Sea contributed 9 MMboe of upward revisions from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 1 MMboe of proved reserves and sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.

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

The impact of the consolidated PSC to proved reserves based on the modernized terms was an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. As of December 31, 2021, approximately 96 percent of the Company’s Egypt reserves were consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.

Approximately 10 percent of the Company’s year-end 2023 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2023, 2022, and 2021 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2023, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.


	United States		Egypt(1)		North Sea		Total(1)

	(In millions)
2023
Cash inflows	$	20,063	$	9,921	$	5,761	$	35,745
Production costs	(7,861)		(1,690)		(2,773)		(12,324)
Development costs	(2,182)		(1,235)		(2,461)		(5,878)
Income tax expense	(936)		(2,222)		(946)		(4,104)
Net cash flows	9,084		4,774		(419)		13,439
10 percent discount rate	(3,534)		(943)		476		(4,001)
Discounted future net cash flows(2)	$	5,550	$	3,831	$	57	$	9,438
2022
Cash inflows	$	29,490	$	12,819	$	10,147	$	52,456
Production costs	(10,221)		(2,086)		(3,241)		(15,548)
Development costs	(1,598)		(1,471)		(2,297)		(5,366)
Income tax expense	(1,389)		(2,729)		(2,631)		(6,749)
Net cash flows	16,282		6,533		1,978		24,793
10 percent discount rate	(6,422)		(1,400)		(204)		(8,026)
Discounted future net cash flows(2)	$	9,860	$	5,133	$	1,774	$	16,767
2021
Cash inflows	$	22,852	$	9,337	$	6,832	$	39,021
Production costs	(8,323)		(1,712)		(2,343)		(12,378)
Development costs	(1,632)		(1,402)		(2,533)		(5,567)
Income tax expense	(134)		(1,887)		(768)		(2,789)
Net cash flows	12,763		4,336		1,188		18,287
10 percent discount rate	(5,294)		(983)		350		(5,927)
Discounted future net cash flows(2)	$	7,469	$	3,353	$	1,538	$	12,360

(1)Includes discounted future net cash flows of approximately $1.8 billion, $2.5 billion, and $1.6 billion as of December 31, 2023, 2022, and 2021, respectively, attributable to noncontrolling interests in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $13.0 billion, $21.7 billion, and $14.9 billion as of December 31, 2023, 2022, and 2021, respectively.

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	For the Year Ended December 31,
	2023		2022		2021

	(In millions)
Sales, net of production costs	$	(5,176)	$	(6,970)	$	(4,707)
Net change in prices and production costs	(6,699)		8,627		9,376
Discoveries and improved recovery, net of related costs	1,633		1,132		1,749
Change in future development costs	(415)		(347)		(839)
Previously estimated development costs incurred during the period	707		669		545
Revision of quantities	(127)		2,621		1,983
Purchases of minerals in-place	—		17		1
Accretion of discount	2,167		1,489		626
Change in income taxes	1,374		(2,371)		(1,583)
Sales of minerals in-place	(18)		(363)		(116)
Change in production rates and other	(775)		(97)		13
	$	(7,329)	$	4,407	$	7,048

F-60