APA (APA) 10-K2023 FY Annual report

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. ☒

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 ☒

 

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, 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, 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 owns consolidated subsidiaries that explore for, develop, and produce 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). 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. 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, Apache Corporation consummated 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 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., 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.

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 refreshed the economic foundation for its business in Egypt with the ratification of a merged concession agreement (MCA) with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC). The MCA consolidated the majority of the Company’s gross acreage and production in Egypt under one concession agreement and refreshed existing development and exploration lease terms.

On January 3, 2024, APA and Callon 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 Permian 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, 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 maintain a balanced asset portfolio, including advancement of 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 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 2023 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.

APA’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. 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.

The following table sets out a brief comparative summary of certain key 2023 data for each of the Company’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.

In 2023, the Company’s U.S. upstream oil and gas operations contributed approximately 54 percent of production, 41 percent of oil and gas revenues, and 70 percent of estimated year-end proved reserves. APA has access to significant liquid hydrocarbons across its 3.7 million gross acres (1.8 million net acres) in the U.S., 76 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. The Company 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. 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:

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.

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 West 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 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 2023, international assets contributed 46 percent of APA’s production and 59 percent of its oil and gas revenues. Approximately 30 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 interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities.

APA’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 the Company’s Egypt operations despite impacting the Company’s production and reserves.

The APA subsidiary that is the sole Contractor under the MCA 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 35 percent of 2023 production and 21 percent of 2023 year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 27 percent of 2023 production and 15 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 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 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.

The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). In 2011, the Company 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. The Company 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.

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.

The Company has 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. TotalEnergies holds a 50 percent working interest in Block 58 as the operator. Key terms of the agreement provide for TotalEnergies to pay 50 percent of all exploration activities and a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation. For the first $10 billion of gross capital expenditures, TotalEnergies pays 87.5 percent, and the Company pays 12.5 percent; for the next $5 billion in gross expenditures, TotalEnergies pays 75 percent and the Company pays 25 percent; and for all gross expenditures above $15 billion, TotalEnergies pays 62.5 percent and the Company pays 37.5 percent. The Company will also receive various other forms of consideration, including a $75 million cash payment upon achieving first oil production and future contingent royalty payments from successful joint development projects.

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 oil production capacity of 200,000 b/d. Detailed engineering studies are underway, and 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 in the 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 as 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 2024. In February 2024, the Company also signed a production sharing contract for Block 4 offshore Uruguay.

In December 2023, the Company suspended further exploration activities in its approximately 630,000 net undeveloped acres offshore the Dominican Republic. The Company has elected to voluntarily relinquish its net acreage holdings and anticipates completion of its withdrawal in early 2024. The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.

Worldwide in 2023, APA drilled or participated in drilling 254 gross wells, with 220 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: 81 gross (74.2 net) in the U.S., 49 gross (49.0 net) in Egypt, 3 gross (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, 2023, is set forth below:

Gross natural gas and crude oil wells included 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, 2023:

As of December 31, 2023, the Company 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 724,000 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 88 percent of U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights.

The Company held approximately 5.4 million net undeveloped acres as of December 31, 2023, in international locations separate from positions held in its established U.K. and Egypt locations. Exploration interests include Block 53 and Block 58 offshore Suriname, Block 6 offshore Uruguay, and offshore the Dominican Republic.

The Company continues to actively evaluate and analyze several discoveries on its Block 58 offshore Suriname exploration acreage with its operator partner, TotalEnergies. Approximately 720,000 net undeveloped acres in Block 58 have a current expiration date of June 2026 assuming no further actions are taken to extend. Separately 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 as of the end of 2023.

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

In December 2023, the Company suspended further exploration activities in its approximately 630,000 net undeveloped acres offshore the Dominican Republic. The Company has elected to voluntarily relinquish its net acreage holdings and anticipates completion of its withdrawal in early 2024.

The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.

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, 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.

As of December 31, 2023, the Company had total estimated proved reserves of 379 MMbbls of crude oil, 173 MMbbls of NGLs, and 1.5 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 807 million boe, of which liquids represent approximately 68 percent. As of December 31, 2023, the Company’s proved developed reserves totaled 735 MMboe and estimated proved undeveloped (PUD) reserves totaled 72 MMboe, or approximately 9 percent of worldwide total proved reserves. APA 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 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of exploration and development adds 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 46 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 37 MMboe.

The Company’s total estimated PUD reserves of 72 MMboe as of December 31, 2023, decreased by 16 MMboe from 88 MMboe of PUD reserves reported at year end 2022. During 2023, the Company converted 39 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 37 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. The Company added 81 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 58 MMboe, comprising 13 MMboe associated with engineering and interest revisions, 16 MMboe associated with revised development plans, and 29 MMboe associated with product prices.

During 2023, a total of approximately $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 2023, the Company spent approximately $323 million on PUD reserve development activity in the U.S. and $54 million in the international areas. As of December 31, 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.

APA’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 the Company’s international proved reserves and 95 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 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:

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 to acquire equity interests in five separate third-party pipeline projects 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. As a result, APA fully consolidated the assets and liabilities of ALTM in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.

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 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.

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.

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, 2023, the Company globally employed approximately 2,271 full-time equivalent employees in locations across the organization.

Amongst the Company’s U.S. workforce, 37 percent self-report as non-white.

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

The Management Development and Compensation (MD&C) Committee and/or the full Board of Directors receive regular reports on certain human capital matters, including the Company’s diversity and inclusion programs and initiatives. The MD&C Committee also oversees the Company’s compensation programs, leadership development and succession planning strategies, and seeks continuous improvement in the diversity and inclusion practices used in developing and deploying these processes. Reports and recommendations made to the Board of Directors and its committees are part of the framework that ensures APA’s daily actions and decisions are guided by its core values, including upholding the health and safety of the Company’s team, stakeholders, and communities; investing in its workforce; ensuring environmental responsibility; seeking continuous improvement; and acting ethically and with integrity.

APA recognizes diversity and inclusion (D&I) as vital to its long-term success. The Company has dedicated resources to developing D&I programs and initiatives that foster an inclusive work environment where all employees are valued. The goal is to create a culture where all employees can feel a sense of belonging and can thrive.

In 2023, APA strengthened its commitment by supporting its established programs and expanding employee engagement through the following key accomplishments:

APA’s comprehensive talent strategy integrates recruitment and development initiatives, forming a foundation for continued organizational success. The Company is dedicated to attracting, cultivating, and retaining top-tier professionals while fostering an environment that encourages growth and innovation.

The Company’s recruitment framework harnesses technology and data-driven insights to identify talent pools on a global scale, while at the local level, the Company leverages the power of its people, including, looking to the Company’s ERG members for recommendations and feedback during the candidate sourcing and interviewing processes.

Collaborations with educational institutions, including HBCUs, industry networks and professional organizations, such as the Posse Foundation, enable the Company to engage with emerging talent and build relationships with seasoned industry professionals. APA has an intern recruitment program that provides invaluable learning experiences and helps cultivate a pipeline of future industry leaders. Additionally, the Company’s recent engagement of the largest black women-owned, diversity-certified recruiting firm specializing in STEM has the goal of amplifying the value and impact of the Company’s recruitment program. The firm’s expertise, dedicated focus on diversity, and vast network in the STEM fields will help expand the Company’s talent pool and reinforce the Company’s commitment to fostering a diverse and inclusive working environment. This collaboration not only aligns with the Company’s corporate goals but also strengthens the Company’s reputation as an organization dedicated to empowering underrepresented groups in STEM. The engagement is a significant stride forward that will enrich the Company’s recruitment initiatives and further its commitment to diversity and excellence in the STEM disciplines.

Beyond recruitment, the Company invests in a broad range of talent development programs for its employees. These initiatives encompass continuous learning opportunities, skill enhancement programs, mentorship frameworks, and leadership development pathways. Tailored career progression opportunities empower the Company’s employees to excel and innovate, preparing them for evolving challenges.

The synergy between recruitment efforts and talent development initiatives helps the Company to not only attract top talent but to also nurture their potential, enabling them to excel within a dynamic environment. This cohesive approach is designed to provide a continuous influx of skilled individuals who contribute significantly to the Company’s growth and maintain a competitive edge, positioning the Company for sustained success in an ever-evolving market landscape.

Supplemental development and training opportunities were offered during the year to support employees in their personal and professional development, including:

Additionally, the Company launched a company-wide initiative in 2023 focused on enhancing talent strategies and investing in employee development programs that enrich the overall employee experience while reinforcing the Company’s organizational objectives.

APA’s priority is the health and safety of its workforce. The Company’s environmental, health, and safety and operations functions partner to consistently reinforce its core values, standards, and operating practices as well as foster a safety culture that empowers the Company’s workforce to stop work if conditions or behaviors are deemed unsafe. APA strives to be incident-free across its global operations every day, with the help of visible and engaged leadership, by setting clear expectations and making safety personal for all employees and contractors.

APA’s global giving strategy and philosophy is focused into three pillars: Community Well-being, Environmental Stewardship, and Access to Energy, through which the Company creates sustainable and positive impacts. Based on these pillars, APA is committed to addressing acute social needs within the local communities where it operates; ensuring that it remains focused on its long-standing legacy and commitment to environmental stewardship and conservation; and supporting underserved communities that lack access to reliable, affordable energy.

APA also provides employees with volunteer service opportunities in collaboration with its Community Partnerships program. The Company seeks meaningful volunteer opportunities that instill a sense of pride, ownership, and accomplishment

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.

The Company’s subsidiaries maintain oil spill response plans (the Plans) for their respective offshore operations in the Gulf of Mexico, the North Sea, and Suriname, 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.

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

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.

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.

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

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:

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.

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.

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.

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 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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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 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 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.

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.

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.

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.

The Company’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 the Company or its subsidiaries or the composition of such lenders.

The payment of future dividends on the Company’s capital stock is subject to the discretion of the Board of Directors, taking into consideration, among other factors, the Company’s operating results, available cash, overall financial condition, credit risks, capital requirements, restrictions under the Company’s indentures and other financing agreements, and restrictions under Delaware law, as well as general business and market conditions. The Board of Directors is not required to declare dividends on APA’s common stock and may decide not to declare dividends.

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 the Company’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 the Company’s securities may be negatively impacted.

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.

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, including Apache. As a result, APA relies on cash flows from its subsidiaries to pay dividends on its common stock and to meet its financial obligations, including to service any amounts outstanding under its credit agreement or commercial paper program, and any additional financial obligations that the Company may incur from time to time in the future. If the subsidiaries are limited in their ability to distribute cash to the Company, such as through legal or contractual limitations, or if the subsidiaries’ earnings or other available assets are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary to meet the Company’s financial obligations, then the Company’s financial condition, cash flows, and reputation may be materially adversely affected.

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 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.

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.

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.

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.

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 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.

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.

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. 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.

The Company’s operations outside the U.S. are based primarily in Egypt and the U.K., with significant exploration and appraisal activities offshore Suriname. On a barrel equivalent basis, approximately 46 percent of the Company’s 2023 production was outside the U.S., and approximately 30 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;

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.

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 a one-third noncontrolling interest, contributed 27 percent of the Company’s 2023 production and accounted for 15 percent of the Company’s year-end estimated proved reserves and 29 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 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.

If the merger is not completed for any reason, including as a result of failure to obtain all requisite regulatory and stockholder approvals, the ongoing business of the Company may be materially adversely affected and, without realizing any of the benefits of having completed the merger, the Company would be subject to a number of risks, including the following:

Whether or not the merger is completed, the announcement and pendency of the merger could cause disruptions to the Company’s business, including:

The success of the merger will depend on, among other things, the combined company’s ability to integrate the Company’s and Callon’s businesses in a manner that realizes anticipated synergies and benefits and meets or exceeds the forecasted stand-alone cost savings anticipated by the combined company. If the combined company is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. If the transaction closes, it is possible that the integration process could result in the loss of key Company employees or key Callon employees, the loss of customers, providers, vendors, or business partners, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures, and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with and following completion of the merger, or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.

In addition, at times the attention of certain members of the Company’s management and resources may be focused on completion of the merger and planning the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to the Company, which may disrupt the Company’s ongoing business and the business of the combined company.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger, or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on the Company’s liquidity and financial condition.

There can be no assurance that any of the defendants will be successful in the outcome of any pending or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the Company’s business, financial condition, results of operations, and cash flows.

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

None.

The program also establishes protocols for identifying and managing material risks related to cybersecurity threats associated with the Company’s use of third-party service providers. The Company monitors and oversees the material risks related to vulnerabilities, threats, and incidents impacting its third-party service providers via onboarding reviews, threat intelligence reports, and annual assessments. As an example of the Company’s efforts to manage third-party cybersecurity risks, when third parties are engaged to provide software-as-a-service offerings, the Company’s standard licensing terms require such third parties to utilize safeguards to protect the Company’s data, in compliance with applicable standards from the International Organization for Standardization (ISO) regarding security techniques, and to notify the Company within 24 hours of becoming aware of a cybersecurity incident impacting the Company’s data.

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.

In 2023, the Company’s Board of Directors established a standing Cybersecurity Committee to assist with oversight of the Company’s cybersecurity program and the material risks associated with the threats identified under the program. Given the Cybersecurity Committee’s chair’s previous military experience in positions relevant to information security and his NACD-sponsored CERT Certificate in Cybersecurity Oversight from Carnegie Mellon University’s Software Engineering Institute, the committee benefits from his perspectives, skills, and training when reviewing and managing the Company’s exposure to cybersecurity risks.

As stated in its charter, the Cybersecurity Committee’s responsibilities include:

The Cybersecurity Committee also has authority to retain cybersecurity and other consultants and advisors to assist and advise the committee in its evaluation of the Company’s cybersecurity program.

The Cybersecurity Committee receives regular reports from Company management regarding the Company’s cybersecurity systems and programs, and the committee from time to time also receives updates from external cybersecurity specialists on cybersecurity trends and incidents, including those that may be particularly relevant to the Company’s industry or operations. In addition, in exercising its oversight responsibilities, the Cybersecurity Committee has full access to Company management and may inquire into any matter that it considers to be of material concern to the committee or the full Board of Directors.

The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee’s discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company’s internal control over financial reporting.

APA’s Chief Information Officer (the CIO) is primarily responsible for the day-to-day operation of the Company’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. The CIO manages the Company’s Information Security Team, which is comprised of cybersecurity professionals responsible for managing the Company’s threat intelligence, vulnerability management, forensics, and security architecture systems and processes. The CIO has a Bachelor of Science in Computer Science and over 25 years of experience managing data and technology in the energy industry. He also receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The CIO reports directly to APA’s Executive Vice President, Administration, who, along with the CIO, presents all relevant information to the Cybersecurity Committee.

Additionally, in 2023, the Company established its CyberSmart Defender Network, which is a multi-disciplinary team that includes representatives from across the Company’s various departments, responsible for raising awareness of cybersecurity issues, sharing learnings, and gaining access to advanced cybersecurity information and training.

Under the direction of the CIO, management’s responsibilities with respect to the Company’s cybersecurity program include (i) identifying and managing cybersecurity risks, (ii) coordinating cybersecurity incident response, (iii) assessing the health and maturity of the Company’s cybersecurity policies, procedures, and plans, including the program, and (iv) reporting overall progress to the Cybersecurity Committee and to the full Board of Directors.

None.

APA’s common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol “APA.” The closing price of APA’s common stock, as reported by the Nasdaq for January 31, 2024, was $31.33 per share. As of January 31, 2024, there were 301,818,820 shares of APA’s common stock outstanding held by approximately 3,000 stockholders of record and 257,000 beneficial owners.

The Company has paid cash dividends on its common stock for 59 consecutive years through December 31, 2023. During the third quarter of 2022, the Company’s Board of Directors increased the Company’s quarterly dividend from $0.125 per share to $0.25 per share, representing a return to pre-Covid-19 dividend levels. When, and if, declared by the Company’s Board of Directors, future dividend payments will depend upon the Company’s level of earnings, financial requirements, and other relevant factors.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2024 annual meeting of stockholders, which is incorporated herein by reference.

The table below sets forth information with respect to shares of common stock repurchased by APA during 2023.

Omitted.

The following discussion relates to APA Corporation (APA 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 Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 (filed with the SEC on February 23, 2023).

On March 1, 2021, Apache Corporation consummated 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 automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation 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 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 Corporation’s primary assets are its ownership interests in its subsidiaries.

APA 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. APA 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 moderate, sustainable production growth; (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, share repurchases, and other return of capital to its shareholders; and (3) to responsibly manage its cost structure regardless of the oil price environment.

The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For example, the Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices but accelerated the completion of eight Permian Basin oil producing wells. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. Capital investment plans were then aligned across other areas of the portfolio while maintaining a focus on the Company’s capital returns framework established in 2021.

The Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns.

During 2023, the Company reported net income attributable to common stock of $2.9 billion, or $9.25 per diluted share, compared to net income of $3.7 billion, or $11.02 per diluted share, 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 $3.1 billion of cash from operating activities in 2023, which was $1.8 billion or 37 percent lower than 2022. APA’s lower operating cash flows for 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 8.7 million shares of its common stock for $329 million and paid $308 million in dividends to APA common stockholders during 2023.

Key operational highlights for the year include:

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.

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 APA’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of acquisitions and 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 acquisitions and divestitures include:

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

The following table presents production volumes by country:

NM — Not Meaningful

The following table presents pricing information by country:

NM — Not Meaningful

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.

Crude oil revenues for 2023 totaled $6.0 billion, an $838 million decrease from the 2022 total of $6.8 billion. A 19 percent decrease in average realized prices reduced 2023 revenues by $1.3 billion compared to 2022, while 8 percent higher average daily production increased revenues by $430 million. Average daily production in 2023 was 203 Mb/d, with prices averaging $80.72 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 15 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 for 2023 totaled $880 million, a $689 million decrease from the 2022 total of $1.6 billion. A 42 percent decrease in average realized prices reduced 2023 revenues by $652 million compared to 2022, while 4 percent lower average daily production decreased revenues by $37 million. Average daily production in 2023 was 828 MMcf/d, with prices averaging $2.91 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 37 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 for 2023 totaled $508 million, a $308 million decrease from the 2022 total of $816 million. A 38 percent decrease in average realized prices primarily drove the decrease in NGL revenues compared to 2022. Average daily production in 2023 was 64 Mb/d, with prices averaging $21.54 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 increased slightly compared to 2022, primarily a result of increased drilling activity and recompletions and less maintenance downtime in the North Sea, offset by natural production decline across all assets.

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.

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.