UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

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

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

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

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

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

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

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

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

 

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 and capital returns framework, the anticipated benefits of the proposed merger (the merger) between the Company and Callon Petroleum Company (Callon), the anticipated impact of the merger on the combined company’s business and future financial and operating results, the anticipated financial and operational impact and timing of the expected synergies from the merger, and the anticipated closing date for the merger, are forward-looking statements. Such forward-looking statements are based on the Company’s examination of historical operating trends, the information that was used to prepare its estimate of proved reserves as of December 31, 2021,2023, 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:

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.

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.

APA Corporation (APA or the Company), is an independent energy company that exploresowns consolidated subsidiaries that explore for, develops,develop, and producesproduce natural gas, crude oil, and NGLs. The Company’s upstream business currently has explorationoil and productiongas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. ThePrior to the BCP Business Combination (as defined below), the Company’s midstream business (Altus Midstream) iswas operated by Altus Midstream Company (Nasdaq: ALTM)(ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

On March 1, 2021, Apache Corporation completedconsummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market (Nasdaq) under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe. As a holding company, APA has no business operations of its own, and its only significant assets are the outstanding equity interests of its subsidiaries. As such, most properties referred to herein are held by subsidiaries of APA.

APA maintains a diversified asset portfolio, including conventional and unconventional, onshore and offshore, oil and natural gas exploration and production interests. In the U.S., APA operations are primarily focused in the Permian Basin of West Texas and Eastern New Mexico, with additional 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. The Company also commenced an exploration program in Alaska during the fourth quarter of 2023. Internationally, the Company has conventional onshore assets in Egypt’s Western Desert, offshore assets on the U.K.’s Continental Shelf, and an offshore appraisal and exploration program in Suriname, and an offshore exploration block in the Dominican Republic.Suriname.

Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, APA has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. Management actively reviews certain non-strategic assets for opportunities, which include potential monetization of legacy properties and other non-core leasehold positions.

In late 2021, the Company made significant progress on key aspects of its portfolio. Specifically, the Company refreshed the economic foundation for its business in Egypt with the announcement of the ratification of a modernized production-sharing contract (PSC)merged concession agreement (MCA) with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC). The new PSC consolidatesMCA consolidated the majority of the Company’s gross acreage and production in Egypt into a singleunder one concession agreement and refreshesrefreshed existing development and exploration lease terms. The modernized PSC incentivizes increased investment and production growth and places Egypt at the top of many attractive investment opportunities in APA’s global portfolio.

On January 3, 2024, APA and related governmental actions. UncertaintyCallon Petroleum Company (Callon) entered into a definitive agreement, pursuant to which APA will acquire Callon in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s net debt. In this all-stock transaction, each eligible outstanding share of Callon common stock will be exchanged for 1.0425 shares of APA common stock. After closing, existing APA shareholders are expected to own approximately 81 percent of the combined company, and existing Callon shareholders are expected to own approximately 19 percent of the combined company. This transaction complements and enhances APA’s asset base in the commodityPermian Basin and adds to APA’s inventory of high quality, short-cycle opportunities. In addition, Callon’s assets provide additional scale to APA’s operations across the Permian Basin.

Uncertainties in the global supply chain and financial markets, since early 2020including 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.demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its stakeholders.shareholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

For a more in-depth discussion of the Company’s 20212023 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

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

APAAPA’s upstream business has explorationoil and productiongas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea. APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities.

In 2021,2023, the Company’s U.S. upstream oil and gas operations contributed approximately 5954 percent of production, 41 percent of oil and 68gas revenues, and 70 percent of estimated year-end proved reserves, consistent with prior years.reserves. APA has access to significant liquid hydrocarbons across its 3.83.7 million gross acres (1.8 million net acres) in the U.S., 7576 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. APAThe Company is one of the largest operators in the Permian Basin, operating approximately 6,0005,000 gross oil and gas wells across its acreage, with additional interests in moreless than 3,000 non-operated wells. Of note, approximately six percent of the Company’s net acreage position in the Permian Basin is on federal onshore lands. APA 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:

APA 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 WTIWest Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’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.

APA’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.

APA currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development, and/or spot market purchases as necessary.third-party purchases. APA 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.

In 2021,2023, international assets contributed 4146 percent of APA’s production and 5059 percent of its oil and gas revenues. Approximately 3230 percent of estimated proved reserves at year-end 2023 were located outside the U.S.

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

The Company also has an active offshore exploration program and appraisal operations ongoing in Suriname, and an offshore exploration blockinterests in the Dominican Republic.

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

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

The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Through the joint venture, Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company’s Egypt assets, including the one-third noncontrolling interest, contributed 3035 percent of 20212023 production and 21 percent of 2023 year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 2227 percent of 20212023 production and 1615 percent of 2023 year-end estimated proved reserves.

In 2021,2023, the Company drilled 3075 gross development and 2448 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 the Company’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering over 3three million acres, which has led to date and continues torecent discoveries that build and enhance itsthe Company’s drilling inventory in Egypt, supplemented with recent seismic acquisitionsEgypt. The Company will continue to focus on driving efficiencies and new play concept evaluations, on both new and existing acreage.

The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, the Company has actively invested in these assets and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of 4-D seismic. Building upon its success in Forties, inIn 2011, the Company acquired Mobil North Sea Limited, providing the Company with additional exploration and development opportunities in the North Sea across numerous fields, includingwhich included operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. The Company also has a non-operated interest in the Nelson field acquired in 2011. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. The North Sea assets play a strategic role in APA’s portfolio by providing competitiveDuring the second quarter of 2023, as part of the Company’s focus on capital allocation to optimize investment opportunities and potential reserve upside with high-impact exploration potential, near existing infrastructure.

The Company’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.

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

During 2023, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an active appraisaloil production capacity of 200,000 b/d. Detailed engineering studies are underway, and exploration program budgeted for 2022.a final investment decision is expected by year-end 2024, with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.

The Company is also the operator of Block 53 offshore Suriname and holds a 45 percent working interest holder in Suriname onthe block. Exploration and evaluation of the area is ongoing. During 2023, the Company was granted an extension to retain approximately 13,000 net undeveloped acres for its operated Baja discovery area, allowing the remaining net undeveloped acres to expire in Block 53 where technical work completedas of the end of 2023.

During 2023, the Company signed a production sharing contract for Block 6 offshore Uruguay covering approximately four million net undeveloped acres and expects to commence exploration activities in 2021 has led to2024. In February 2024, the resumption ofCompany also signed a production sharing contract for Block 4 offshore Uruguay.

In December 2023, the Company suspended further exploration activities. An exploration well is planned for early 2022 with partners CEPSA and Petronas who have a 25 percent and 30 percent working interest, respectively.

Worldwide in 2021,2023, APA drilled or participated in drilling 166254 gross wells, with 145220 wells (87 percent) completed as producers. Historically, APA’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: 5381 gross (41.7(74.2 net) in the U.S., 2249 gross (22.0(49.0 net) in Egypt, 13 gross (1(2.5 net) in the North Sea, and 1 gross (0.5 net) in Suriname.

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

The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2021,2023, is set forth below:

Gross natural gas and crude oil wells include 494included 457 wells with multiple completions.

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:

The following table summarizes the Company’s gross and net acreage position by geographic area as of December 31, 2021:2023:

As of December 31, 2021,2023, the Company held 636,000approximately 117,000 net undeveloped acres that are scheduled to expire by year-end 20222024 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 10,000approximately 16,000 and 97,000724,000 net undeveloped acres set to expire by year-end 20232025 and 2024,2026, 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.

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, APA 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. The Company 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, 2021,2023, based on average commodity prices in effect on the first day of each month in 2021,2023, 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.

During 2021,2023, the Company added 102approximately 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of proved reserves through exploration and development activity. There were also upwardadds in the U.S., comprising 67 MMboe in the Permian Basin, 27 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 107 MMboe. Upward46 MMboe, primarily driven by revisions related toin the U.S. Downward revisions for price and interest changes in product prices accounted for 85 MMboe. Engineering83 MMboe, offset by engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operations. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to the Permian Basin.

The Company’s total estimated PUD reserves of 8572 MMboe as of December 31, 2021, increased2023, decreased by 916 MMboe from 7688 MMboe of PUD reserves reported at year end 2020.2022. During the year,2023, the Company converted 3339 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 2837 MMboe, with the remaining 52 MMboe in its international areas. The Company sold 2 MMboe of PUD reserveshad no sales nor purchases in the U.S. and did not acquire anyplace related to PUD reserves during the year.2023. The Company added 6381 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 1958 MMboe, comprising 713 MMboe associated with engineering and interest revisions, 1116 MMboe associated with revised development plans, and 129 MMboe associated with product prices.

During 2021,2023, a total of approximately $213$377 million was spent on projects associated with proved undeveloped reserves. A portion of APA’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2021,2023, the Company spent approximately $174$323 million on PUD reserve development activity in the U.S. and $39$54 million in the international areas. As of December 31, 2021,2023, the Company had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.

The Company’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.

APA’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 the Company’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 APA’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our corporate and operating asset engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year, and reserves volume. During 2021,2023, the properties selected for each country ranged from 82 to 84all countries represented 88 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 8391 percent of the value of the Company’s international proved reserves and 9495 percent of the value of the Company’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 8083 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 reviewreviews for the years 2023, 2022, and 2021 2020, and 2019 covered 83, 85, and 87 percent, respectively, of the value and 80, 81, and 85 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2021 review covered 80, 80, and 81 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.were:

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 the Company, the overall procedures and methodologies utilized by the Company in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by the Company are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.

In November 2018, Apache Midstream LLC, one of the Company’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, the Company’s subsidiary contributed certain Alpine High midstream assets and options (the Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, the Company’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.

On October 21, 2021,February 22, 2022, ALTM closed a previously announced that it willtransaction 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 dated as of that same date and entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination createscreated an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. There are numerous expected commercial and financial synergies generated from the complementary midstream systems and enhanced scale of the business. The combined business will have a more diversified asset profile and customer base, with a lower risk profile than either entity on a stand-alone basis. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline. Pursuant to the BCP Contribution Agreement, Contributor will contributecontributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination).

As consideration for the contribution of the Contributed Interests, ALTM will issueissued 50 million shares of Class C Common Stock (and Altus Midstream LP will issueissued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to closeclosed during the first quarter of 2022 following completion of customary2022. Upon closing conditions.

After the transaction closed, Apache Midstream LLC, a wholly owned subsidiary of APA, which currently ownsowned approximately 79 percent of the issued and outstanding shares of ALTM Common Stock, will owncommon 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 Common Stock, andin its consolidated financial statements. Subsequent to the remaining current stockholders will own approximately 5 percentclose of the issued and outstanding sharestransaction, in March 2022, the Company sold four million of ALTM Common Stock.

In December 2023, the Company sold an additional 7.5 million of its Alpine High resource play.Kinetik Shares for cash proceeds of $228 million. As of December 31, 2021, Altus’ assets included2023, the Company owned 13.1 million Kinetik Shares, representing approximately 182 miles9 percent of in-service natural gas gathering pipelines, approximately 46 miles of residue-gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Altus’ existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and third-party customers as market activity in the area continues to develop.Kinetik’s outstanding common stock.

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 production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.

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

APA believes that its people are one of the Company’s most important investments and its greatest asset. Successful execution of the Company’s business strategies depends on its ability to attract, develop, incentivize, and retain diverse, talented, qualified, and highly skilled employees at all levels of the organization. As such, the Company continues to focus on health and safety, diversity and inclusion, total rewards, and community partnerships to ensure that being a part of the APA family is a positive experience for all.

As of December 31, 2021,2023, the Company globally employed approximately 2,2532,271 full-time equivalent employees in locations across the organization.

Amongst the Company’s U.S. workforce, 3437 percent self-report as non-white.

The Company does not request racial diversity data from its non-U.S. colleagues,workforce in countries outside of the U.S. where tracking these metrics is largely prohibited by law.