Apa Corp,
Fiscal Year 2023.

NGL Revenues 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 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. 41

Gathering, Processing, and Transmission (GPT) GPT expenses include amounts paid to third-party carriers for gathering and transmission services for the Company's upstream natural gas production. Prior to the BCP Business Combination and the Company's deconsolidation of Altus on February 22, 2022, GPT expenses also included gathering and transmission services provided by Altus Midstream and midstream operating costs incurred by Altus. The following table presents a summary of these expenses: For the Year Ended December 31,

Key operational highlights for the year include: United States •Daily boe production from the Company's U.S. assets, which increased 2 percent from 2022, accounted for 54 percent of the Company's worldwide production during 2023. The Company averaged five drilling rigs in the U.S. during the year, including three rigs in the Southern Midland Basin and two rigs in the Delaware Basin, and drilled and brought online 82 operated wells in 2023. The Company's drilling was primarily focused on oil prospects, increasing oil production by approximately 12 percent in the U.S. compared to the prior year. The Company's core Permian Basin development program continues to represent key growth areas for the U.S. assets. •During the fourth quarter of 2023, the Company commenced an exploration program in Alaska, where it anticipates drilling three exploration wells in the first half of 2024.

Taxes Other Than Income Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes. Taxes other than income decreased $61 million compared to 2022, primarily from lower severance taxes driven by lower commodity prices and lower ad valorem tax rates.

As of December 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $824 million to $1.2 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $824 million as of December 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $764 million is reflected under the caption "Decommissioning contingency for sold Gulf of Mexico properties," and $60 million is reflected under "Other current liabilities" in the Company's consolidated balance sheet. Changes in significant assumptions impacting Apache's estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. As of December 31, 2023, the Company has also recorded a $199 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $21 million is reflected under the caption "Decommissioning security for sold Gulf of Mexico properties," and $178 million is reflected under "Other current assets." The Company recognized $212 million, $157 million, and $446 million during 2023, 2022, and 2021, respectively, of "Losses on previously sold Gulf of Mexico properties" to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company's statement of consolidated operations. 54 On June 21, 2023, the two sureties that issued bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. Insurers are seeking to prevent Apache from drawing on the Bonds and Letters of Credit and further allege that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers' request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division) which subsequently held that the sureties' state court lawsuit violated the terms of the Bankruptcy Confirmation Order and is void. Apache has drawn down the entirety of the Letters of Credit and is vigorously pursuing its claims against the sureties.

Offshore Decommissioning Contingency The Company has potential exposure to future obligations related to divested properties. For information regarding estimated potential decommissioning obligations on sold properties, please refer to "Potential Decommissioning Obligations on Sold Properties" above and in Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K. The Company's estimated contingent obligation is primarily associated with the abandonment, removal and decommissioning of offshore wells and platforms in the Gulf of Mexico. Estimating any future obligation requires significant judgment. The Company utilizes actual abandonment and decommissioning costs incurred as the basis to estimate the expected cash outflows for future obligations. Actual costs incurred often vary based on each structure's condition, depth-of-water, type, and other similar factors, which are key considerations when estimating the remaining well and platform decommissioning obligation. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations. Changes in significant assumptions or the regulatory framework impacting the Company's estimated liability could result in a liability in excess of the amount accrued.

Other, net11 20 - 5,980 4,197 3,170 Uses of Cash and Cash Equivalents: Additions to upstream oil and gas property(1) 1,770 1,101 1,270 Acquisition of Delaware Basin properties591 - -

The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time. 50 Dividends Paid to APA Common Stockholders The Company paid $207 million and $52 million during the years ended December 31, 2022 and 2021, respectively, for dividends on its common stock. During the third quarter of 2021, the Company's Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625 and, in the fourth quarter of 2021, a further increase to $0.125 per share. During the third quarter of 2022, the Company's Board of Directors approved a further increase to its quarterly dividend to $0.25 per share. Distributions to Noncontrolling Interest - Egypt Sinopec holds a one-third minority participation interest in the Company's oil and gas operations in Egypt. The Company paid $362 million and $279 million during the years ended December 31, 2022 and 2021, respectively, in cash distributions to Sinopec. Distributions to Altus Preferred Unit Limited Partners Prior to the deconsolidation of Altus on February 22, 2022, Altus Midstream LP paid $11 million and $46 million in cash distributions to its limited partners holding Preferred Units during the years ended December 31, 2022 and 2021, respectively. For more information regarding the Preferred Units, refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Treasury Stock Activity, Net During 2022, the Company repurchased 36.2 million shares at an average price of $39.34 per share totaling $1.4 billion, and as of December 31, 2022, the Company had remaining authorization to repurchase 52.6 million shares. During 2021, the Company repurchased 31.2 million shares at an average price of $27.14 per share totaling $847 million.

Reserves Estimates Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. 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. Despite significant judgment involved in these engineering estimates, the Company's reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company's supplemental oil and gas disclosures. For more information regarding the Company's supplemental oil and gas disclosures, refer to Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Income Taxes The Company's oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company's deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). The Company regularly assesses and, if required, establishes accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law, and any new legislation. The Company believes that its accruals for uncertain tax positions are adequate in relation to the potential for any additional tax assessments.

ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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.

217,266 2%212,007 (8)%229,348 Egypt(3)(4) 143,425 (1)%144,665 26%114,821 North Sea(2) 44,349 12%39,577 (10)%43,892 Total405,040 2%396,249 2%388,061 (1)The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products. (2)Average sales volumes from the North Sea were 45,476 boe/d, 40,812 boe/d, and 44,179 boe/d for 2023, 2022, and 2021, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Oil (b/d)573 777 1,485 Natural Gas (Mcf/d)174,454 192,253 258,096 NGL (b/d)16,482 18,362 22,950 NM - Not Meaningful 39 Pricing The following table presents pricing information by country: For the Year Ended December 31,

North Sea47.77 (29)%67.07 24%54.30 Total21.54 (38)%34.51 21%28.48 NM - Not Meaningful Crude Oil Prices A substantial portion of the Company's crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company's control. Average realized crude oil prices for 2023 were down 19 percent compared to 2022, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2023 averaged $80.72 per barrel. Continued volatility in the commodity price environment reinforces the importance of the Company's asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Prices for all types and grades of crude oil generally move in the same direction. Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company's primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company's primary gas-producing regions follows: •The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company's U.S. realizations averaged $1.80 per Mcf in 2023, a 66 percent decrease from an average of $5.31 per Mcf in 2022. •In Egypt, the Company's natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company's Egypt operations averaged $2.91 per Mcf in 2023, a 2 percent increase from an average of $2.85 per Mcf in 2022. •Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company's North Sea operations averaged $13.02 per Mcf in 2023, a 44 percent decrease from an average of $23.36 per Mcf in 2022. 40 NGL Prices The Company's U.S. NGL production, which accounted for 98 percent of the Company's total 2023 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Natural Gas Revenues 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.

Depreciation, depletion, and amortization: Oil and gas property and equipment1,500 1,186 1,255 Gathering, processing, and transmission assets6 15 64

Other assets34 32 41 Asset retirement obligation accretion116 117 113 Impairments61 - 208 Financing costs, net312 379 514 Lease Operating Expenses (LOE) LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 50 percent of the Company's total 2023 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties. During 2023, LOE decreased $8 million, or 1 percent, compared to 2022. On a per-boe basis, LOE decreased $0.27, or 3 percent, compared to 2022, from $9.95 per boe to $9.68 per boe. The decrease in costs was driven by lower average foreign currency exchange impacts against the U.S. dollar and decreased workover activity primarily in the North Sea. These decreases were mostly offset by higher labor costs and other operating costs trending with general inflation across all regions.

202320222021 (In millions) Third-party processing and transmission costs$225 $269 $232 Midstream service costs - ALTM - 18 128 Midstream service costs - Kinetik

109 93 - Upstream processing and transmission costs334 380 360 Midstream operating expenses- 5 32 Intersegment eliminations- (18)(128) Total Gathering, processing, and transmission$334 $367 $264 42 GPT costs decreased $33 million compared to 2022, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $46 million from 2022, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company's consolidated financial statements and reflected as "Intersegment eliminations" in the table above. Subsequent to the Company's deconsolidation of Altus in February 2022, these midstream services continue to be provided by Kinetik but are no longer eliminated.

General and Administrative (G&A) Expenses G&A expenses decreased $132 million compared to 2022, primarily driven by lower cash-based stock compensation expense during 2023 resulting from decreases in the Company's stock price and in the achievement of performance and financial objectives as defined in the stock award plans. For additional information refer to Note 14-Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Interest expense$351 $332 $419 Amortization of debt issuance costs4 8 8 Capitalized interest(24)(18)(9) Loss (gain) on extinguishment of debt(9)67 104

202320222021 (In millions) Sources of Cash and Cash Equivalents: Net cash provided by operating activities$3,129 $4,943 $3,496 Proceeds from revolving credit facilities, net

Sources of Cash and Cash Equivalents Net Cash Provided by Operating Activities Operating cash flows are the Company's primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense. Net cash provided by operating activities for the year ended December 31, 2023 totaled $3.1 billion, down $1.8 billion from the year ended December 31, 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items. For a detailed discussion of commodity prices, production, and operating expenses, refer to "Results of Operations" in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Proceeds from Asset Divestitures The Company received $29 million and $778 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2023 and 2022, respectively. For more information regarding the Company's acquisitions and divestitures and equity method interests, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Proceeds from Sale of Kinetik Shares The Company received $228 million and $224 million of cash proceeds from the sales of its Kinetik Shares during 2023 and 2022, respectively. For more information regarding the Company's equity method interests, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 47

Uses of Cash and Cash Equivalents Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $2.3 billion and $1.8 billion for the years ended December 31, 2023 and 2022, respectively. The increase is reflective of the Company's capital program in 2023 and its focus to balance capital investments with cash flow from operations, debt repayment, and capital returns to shareholders. The Company operated an average of 24 drilling rigs during 2023, compared to an average of 22 drilling rigs during 2022. Acquisition of Delaware Basin Properties During 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during 2023. Cash consideration paid during 2022 totaled $591 million. Leasehold and Property Acquisitions During 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $20 million and $37 million, respectively. Payments on Revolving Credit Facilities, Net As of December 31, 2023, outstanding borrowings under the Company's U.S. dollar denominated syndicated credit facility were $372 million, a decrease of $194 million from December 31, 2022 as operating cash flows generated in 2023 were used to repay facility borrowings. Payments on Fixed-Rate Debt During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache's borrowing under the Company's US dollar-denominated revolving credit facility. During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache's former revolving credit facility. During 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache's former revolving credit facility. On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed in part by Apache's borrowing under the Company's U.S. dollar-denominated revolving credit facility. On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache's former revolving credit facility.

Liquidity The following table presents a summary of the Company's key financial indicators as of December 31: 20232022 (In millions) Cash and cash equivalents$87 $245

Contractual Obligations Purchase Obligations From time to time, the Company enters into agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments and agreements to secure capacity rights on third-party pipelines. As of December 31, 2023, the Company had contractual obligations totaling $1.7 billion, of which $956 million is related to U.S. firm transportation contracts, $614 million is related to the merged concession agreement with the EGPC, and $135 million is related to other items. Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2023, the Company has spent $2.9 billion and believes it will be able to satisfy the remaining obligation within its current exploration and development program. Leases In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 842 (Leases). As of December 31, 2023, the Company had net undiscounted minimum commitments of $346 million and $41 million for operating and finance leases, respectively. Interest Expense Future interest payments based on the current maturity dates of the Company's fixed-rate notes and debentures as of December 31, 2023 are approximately $3.9 billion. 52 For additional information regarding these obligations, refer to Note 9-Debt and Financing Costs and Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. For information regarding the Company's liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations, refer to Notes 8-Asset Retirement Obligation and Note 12-Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. The Company is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. The Company's management believes that it has adequately reserved for its contingent obligations, including approximately $5 million for environmental remediation and approximately $83 million for various contingent legal liabilities. For a detailed discussion of the Company's environmental and legal contingencies and other commitments, please see Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies' oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM's website as "rescinded," if reinstated, the NTL will likely require that the Company provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company's current ownership interests in various Gulf of Mexico leases. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which the Company has sold Gulf of Mexico assets or with whom the Company has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties' solvency and ability to continue as a going concern.

Potential Decommissioning Obligations on Sold Properties The Company's subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA's subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise. In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing Fieldwood's asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets. 53 On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood's bankruptcy plan. On August 27, 2021, Fieldwood's bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf's limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf's notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf's notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf's notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets. As of December 31, 2023, Apache has incurred $819 million in decommissioning costs related to Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs. As of December 31, 2023, $293 million has been reimbursed from Trust A and $336 million has been reimbursed from the Letters of Credit. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets. If the combination of GOM Shelf's net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf's net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to use its available cash to fund the deficit.

202320222021 $ Value% Contribution$ Value% Contribution$ Value% Contribution ($ in millions) Oil Revenues: United States$2,241 37 %$2,458 36 %$1,850 40 %

Enhanced focus on ESG matters could have an adverse effect on the Company's operations. Enhanced focus on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory review, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company's access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and regulatory approvals. Negative public perception could cause the permits or regulatory approvals the Company requires to be withheld, delayed, or burdened by requirements that restrict the Company's ability to profitably conduct its business. The Company's estimates used in various scenario planning analyses could differ materially from actual results and could expose the Company to new or additional risks. Given the dynamic nature of the Company's business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company's internally prepared base-case pricing analysis averaged out to the year 2040. Given the numerous estimates that are required to run these scenarios, the Company's estimates could differ materially from actual results. The Company publicly discloses these metrics and its related assumptions and analysis in its annual sustainability report. By electing to disclose these metrics, the Company may face increased scrutiny related to its ESG initiatives. Any harm to the Company's reputation resulting from publicly disclosing such these metrics, expanding disclosures related to such metrics, or failing to achieve such metrics or abiding by such disclosures could adversely affect the Company's business, financial performance, and growth. The guidance upon which the Company's consumptive water use reporting was modified and could be revised in the future, resulting in the over or underreporting of the Company's consumptive water use. In 2022, the Company modified the way it reports its water data compared to previous years and restated its data from prior years. Previously, the Company included produced water usage in its consumptive use calculations, which led to an over-reporting of consumptive water use. Based on re-evaluation of water reporting definitions and guidance, the Company determined that produced water (non-potable water released from deep underground formations and brought to the surface during oil and gas exploration and production) should not be classified as consumed in the same sense as fresh water. The Company's revised reporting now reflects only fresh water and non-potable water from surface water or shallow groundwater that are consumed in oil and gas operations. The treatment and disposal of produced water is becoming more highly regulated and restricted and could expose the Company to additional costs or limit certain operations. The treatment and disposal of produced water is becoming more highly regulated and restricted. Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection) and to require the monitoring of seismic activity. While the Company remains focused on reusing or recycling water over disposal of water, the Company's costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water and restrictions related to disposal wells may increase the Company's operating costs or capital expenses or cause the Company to limit production, which could materially and adversely affect its business, results of operations, and financial conditions.

RISKS RELATED TO INTERNATIONAL OPERATIONS International operations have uncertain political, economic, and other risks. The Company's operations outside the U.S. are based 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; 27 exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds; constrained oil or natural gas markets dependent on demand in a single or limited geographical area; laws and policies of the U.S. affecting foreign trade, including trade sanctions; the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates; the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and difficulties in enforcing the Company's rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company's interests could decrease in value or be lost. Even the Company's smaller international assets may affect its overall business and results of operations by distracting management's attention from its more significant assets. Certain regions of the world in which the Company operates have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as the Company's. In an extreme case, such a change could result in termination of contract rights and expropriation of the Company's assets. This could adversely affect the Company's interests and its future profitability. The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which the Company operates, may have on the oil and gas industry in general and on the Company's operations in particular is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets or indirect casualties of an act of terror or war. The Company may be required to incur significant costs in the future to safeguard its assets against terrorist activities. A further deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on the Company's business. Further deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company's assets or resource nationalization, and/or forced renegotiation or modification of the Company's existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company's business and operations. Additionally, deteriorating economic conditions in Egypt have led to a shortage of foreign currency, including U.S. dollars, resulting in a decline in the timeliness of payments from EGPC. A continuation or worsening of the currency shortage in Egypt or further deterioration of economic conditions there could lead to additional payment delays, deferrals of payment, or non-payment in the future. The Company's operations in Egypt, excluding the impacts of 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 may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves. Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, the Company will focus its review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit the Company as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company often assumes certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon the Company's operating results, particularly during the periods in which the operations of acquired businesses are being integrated into the Company's ongoing operations.

Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly. There are numerous uncertainties inherent in estimating crude oil, natural gas, and NGL reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas, and NGLs that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise and a function of the quality of available data and the engineering and geological interpretation. The Company's reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of 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 effects of regulations by governmental agencies, including changes to severance and excise taxes, future operating costs and capital expenditures, and workover and remediation costs. For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties, classifications of those reserves, and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue, and expenditures with respect to the Company's reserves likely will vary, possibly materially, from estimates. Additionally, because some of the Company's reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on 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. 22 Certain of the Company's undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. A sizeable portion of the Company's acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company's drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

The Company's ability to declare and pay dividends is subject to limitations. The payment of future dividends on the Company's capital stock is subject to the discretion of the Company's board of directors, which considers, among other factors, the Company's operating results, overall financial condition, credit-risk considerations, and capital requirements, 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. Any indentures and other financing agreements that the Company enters into in the future may limit its ability to pay cash dividends on its capital stock, including APA common stock. In addition, under Delaware law, dividends on capital stock may only be paid from "surplus," which is the amount by which the fair value of the Company's total assets exceeds the sum of its total liabilities, including contingent liabilities, and the amount of its capital; if there is no surplus, cash dividends on capital stock may only be paid from the Company's net profits for the then-current and/or the preceding fiscal year. Further, even if the Company is permitted under its contractual obligations and Delaware law to pay cash dividends on common stock, the Company may not have sufficient cash to pay dividends in cash on its common stock. Actions by advocacy groups to advance climate change and energy transition initiatives, unfavorable ESG ratings, and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from companies in the oil and gas industry, which could negatively impact the Company's access to and costs of capital or the market for the Company's securities. Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. Unfavorable ESG ratings may lead to negative investor and public sentiment toward the Company, which may cause the market for the Company's securities to be negatively impacted. In addition, a number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to influence change in the business strategies in 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 activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of investments in the oil and gas industry, as well as pressuring 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.

The Company faces strong industry competition that may have a significant negative impact on the Company's results of operations. Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes with major integrated and other independent oil and gas companies for acquisitions of oil and gas leases, properties, and reserves, equipment and labor required to explore, develop, and operate those properties, and marketing of crude oil, natural gas, and NGL production. Crude oil, natural gas, and NGL prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of the Company's competitors have financial and other resources substantially larger than the Company possesses and 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 25 may be at a competitive disadvantage in bidding for drilling rights. In addition, many of the Company's larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. The Company also competes in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on the Company's results of operations. The Company's ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change. As described in Note 10-Income Taxes of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an "ownership change" under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company's equity ownership by five-percent shareholders over a three-year period, the Company's ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company's operating results or cash flows by effectively increasing its future tax obligations.

RISKS RELATED TO THE HOLDING COMPANY REORGANIZATION APA is dependent on the operations and funds of its subsidiaries, including Apache. As a result of the Holding Company Reorganization, APA became the successor issuer to, and parent holding company of, Apache. 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, including Apache, to pay dividends with respect to APA's common stock and to meet its financial obligations, including to service any debt obligations that the Company may incur from time to time. Legal and contractual restrictions in agreements governing future indebtedness of Apache, as well as Apache's financial condition and future operating requirements, may limit Apache's ability to distribute cash to the Company. If Apache is limited in its ability to distribute cash to the Company, or if Apache's earnings or other available assets of are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary for it to pay dividends with respect to its common stock and/or to meet its financial obligations, then the Company's business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.

Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact the Company's business. Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company's operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company's cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding legislation or regulation of GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions. Moreover, in January 2021, the President issued an executive order that commits to substantial action on climate change, calling for, among other things, the elimination of subsidies provided to the fossil fuel industry and increased emphasis on climate-related risk across governmental agencies and economic sectors. 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 or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas, and NGLs. Additionally, political, litigation, and financial risks related to climate change may result in curtailed refinery activity, increased regulation, or other adverse direct and indirect effects on the Company's business, financial condition, and results of operations. For example, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. 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.

The Company has previously not realized, and may in the future not realize, an adequate return on wells that it drills. Drilling for oil and gas involves numerous risks, including the risk that the Company will not encounter commercially productive oil or gas reservoirs. The wells the Company drills or participates in may not be productive, and the Company may not recover all or any portion of its investment in those wells. Management has previously determined, and may in the future determine, that future or further drilling or development activities will not, or are unlikely to, occur for a well or reservoir based 19 on drilling results, current or future estimated commodity prices or demand for oil, natural gas, and NGLs, or other information, including drilling results in, or information related to, adjacent or nearby geographic areas or similar geologies or reservoirs. The seismic data and other technologies that the Company uses do not allow it to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors, including, but not limited to, unexpected drilling conditions; pressure or irregularities in formations; equipment failures or accidents; fires, explosions, blowouts, and surface cratering; marine risks, such as capsizing, collisions, and hurricanes; other adverse weather conditions; and increases in the cost of or shortages or delays in the availability of drilling rigs, equipment, and labor. Future drilling activities may not be successful, and, if unsuccessful, such failure could have an adverse effect on the Company's future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. 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.

RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS The Company's operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of equipment, and environmental accidents. The Company's operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including well blowouts, explosions, fires, and cratering; pipeline or other facility ruptures and spills; formations with abnormal pressures; equipment malfunctions; hurricanes, major storms, and cyclones, which could affect the Company's operations in areas such as on and offshore the Gulf Coast, North Sea, and Suriname, and other natural and anthropogenic disasters and weather conditions; and surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives. Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters, such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where the Company's equipment and services are used, or ground water contamination from chemical additives used in hydraulic fracturing may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of the Company's production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company's cash flows and, in turn, its results of operations could be materially and adversely affected.

RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production. The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless the Company adds reserves through exploration and development activities, identifies additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquires additional properties containing proved reserves, the Company's estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon the Company's level of success in acquiring or finding additional reserves on an economic basis. Furthermore, as oil or natural gas prices increase, the Company's cost for additional reserves could also increase.

ITEM 1A.RISK FACTORS 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.

RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NGLs Crude oil, natural gas, and NGL prices and their volatility could adversely affect the Company's operating results and the price of APA's common stock. The Company's revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2023 ranged from a high of $93.67 per barrel to a low of $66.61 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2023 ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond the Company's control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including: •worldwide and domestic supplies and/or inventories of crude oil, natural gas, and NGLs and the availability of related pipeline, transportation, import/export, and refining capacity and infrastructure; •actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+); •political conditions and events in oil and gas producing regions, including instabilities, changes in governments, or armed conflicts, such as the Russian war in Ukraine and the armed conflict in Israel and Gaza; •the price, competitiveness, decision to use, and availability of alternative fuels and energy sources, including coal, biofuels, and renewables; •increased competitiveness of, and demand for, alternative energy sources; •technological advances affecting energy supply and energy consumption, including those that alter fuel choices; •the availability of pipeline capacity and infrastructure; •the availability of crude oil transportation and refining capacity; •weather conditions; •the impact of political pressure and the influence of environmental groups, investors, and other stakeholders on decisions and policies related to the oil and gas industry, including with respect to environmental, social, and governance matters; •domestic and foreign governmental regulations and taxes, including changes or initiatives to address the impacts of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and

RISKS RELATED TO CAPITAL MARKETS A downgrade in the Company's credit rating could negatively impact its cost of and ability to access capital. The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company's credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company's ability to access debt markets in the future and increase the cost of future debt. During 2023, Moody's upgraded the Company's rating to Baa3/Stable, and Standard and Poor's affirmed the Company's rating as BB+/Positive. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations. Market conditions may restrict the Company's ability to obtain funds for future development and working capital needs, which may limit its financial flexibility. The financial markets are subject to fluctuation and are vulnerable to unpredictable swings. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company's future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of the Company's property interests. 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.

RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS The Company may incur significant costs related to environmental matters. As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, require significant capital expenditures to comply with increasingly strict environmental laws and regulations, and require suspension or cessation of operations in affected areas. The Company's efforts to limit its exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company's results of operations and cash flows.

RISKS RELATED TO CLIMATE CHANGE The impacts of energy transition could adversely affect the Company's business, operating results, and financial condition. In recent years, increasing attention has been given to corporate activities related to climate change and energy transition. This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power, and the development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more energy-efficient products and services. These developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for, and in turn the prices the Company receives for, its crude oil, natural gas, and NGL products, which could materially and adversely affect the Company's business and financial performance.

Other Exploration New Ventures APA's international New Ventures acreage provides exposure to new growth opportunities outside of the Company's traditional core areas and provides higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. 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. 6

Asian8 % Black or African American6 % Hispanic/Latino22 % Native Hawaiian or Other Pacific Islander- % Two or More Races1 % White63 % 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. 13

•Ongoing education for people leaders around the Company's leadership competencies and behaviors; and •Annual compliance, antitrust, bribery, corruption, and code of business conduct and ethics training required for all employees and leaders. 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.

MAJOR CUSTOMERS The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 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. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company's worldwide crude oil, natural gas, and NGLs revenues.

ADDITIONAL INFORMATION ABOUT THE COMPANY Response Plans and Available Resources The Company's subsidiaries developed 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. Apache also has a contract for response resources and services with National Response Corporation (NRC). NRC is the world's largest commercial Oil Spill Response Organization and is the global leader in providing end-to-end environmental, industrial, and emergency response solutions with operating bases in 13 countries. 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 was created to provide a means of effectively staging response equipment and to provide spill response capability for its member companies operating 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, covering Suriname operations and other drilling activities. The Company utilizes a detailed Source Control Emergency Response Plan (SCERP) for offshore Suriname 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. 16

ITEMS 1 and 2.BUSINESS AND PROPERTIES GENERAL 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. The Company's common stock, par value $0.625 per share, is listed on the Nasdaq. Through the Company's website, www.apacorp.com, you can access, free of charge, electronic copies of the charters of the committees of the Company's board of directors (Board of Directors), other documents related to corporate governance (including the Code of Business Conduct and Ethics and APA's Corporate Governance Principles), and documents the Company files with the SEC, including the Company's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act. Included in the Company's annual and quarterly reports are the certifications of its principal executive officer and its principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after the Company files such material with, or furnishes it to, the SEC. You may also request printed copies of the Company's corporate charter, bylaws, committee charters, or other governance documents free of charge by writing to the Company's corporate secretary at the address on the cover of this Annual Report on Form 10-K. The Company's reports filed with the SEC are made available on its website at www.sec.gov. From time to time, the Company also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on the Company's website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

BUSINESS STRATEGY 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. 1 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 February 22, 2022, ALTM closed on a transaction to combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik), and APA's ownership in ALTM was reduced from approximately 79 percent to approximately 20 percent. Upon closing the transaction, the Company deconsolidated ALTM. The deconsolidation provides a number of benefits to APA shareholders, including simplification of the Company's financial reporting and enhanced comparability with its upstream-only peers, while maintaining a noncontrolling interest in future growth opportunities of Kinetik. Subsequent sales of the Company's shares of Kinetik Class A Common Stock (Kinetik Shares) have reduced APA's ownership in Kinetik to approximately 9 percent. 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. 2

•the North Sea, which includes offshore assets based in the U.K. 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. Egypt APA has decades of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt's Western Desert. At year-end 2023, the Company held 5.3 million gross acres in six separate concessions. The Company's acreage is primarily held under one concession agreement that resulted from the ratification of a new MCA with the Egyptian Ministry of Petroleum and EGPC. The MCA, which has an effective date of April 1, 2021, consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company's production covered under the concession. Development leases within concessions currently have expiration dates ranging from 1 to 20 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Approximately 67 percent of the Company's gross acreage in Egypt is undeveloped, providing APA with considerable exploration and development opportunities for the future. 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. North Sea The Company has interests in approximately 292,000 gross acres in the U.K. North Sea. These assets contributed 11 percent of the Company's 2023 production and approximately 9 percent of year-end 2023 estimated proved reserves. 5 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.

Drilling Statistics 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.

Egypt(1) 25.7 0.2 96.2 11.48 70.33 48.84 2.81 North Sea(2) 13.2 0.4 14.1 26.12 69.67 54.30 12.96 Total66.3 24.8 302.8 11.31 68.97 28.48 3.99 (1)Includes production volumes attributable to a one-third noncontrolling interest in Egypt. (2)Sales volumes from the Company's North Sea assets for 2023, 2022, and 2021 were 16.6 MMboe, 14.9 MMboe, and 16.1 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Gross and Net Undeveloped and Developed Acreage The following table summarizes the Company's gross and net acreage position by geographic area as of December 31, 2023:

UPSTREAM EXPLORATION AND PRODUCTION Operating Areas 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. ProductionPercentageof TotalProductionProductionRevenueYear-EndEstimatedProvedReservesPercentageof TotalEstimatedProvedReservesGrossWellsDrilledGrossProductiveWellsDrilled

The Company continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations. Estimated Proved Reserves and Future Net Cash Flows Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the "economic interest" method, which excludes the host country's share of reserves. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the "proved" classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, 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. 9 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.

Proved Undeveloped: United States31 18 99 66 Egypt(1) 5 - 3 6 North Sea- - - - Total36 18 102 72 Total Proved379 173 1,530 807 (1)Includes total proved developed and total proved undeveloped reserves of 55 MMboe and 2 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt. 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 estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2023, 2022, and 2021, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves The Company's total estimated PUD reserves of 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. 10 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.

Preparation of Oil and Gas Reserve Information 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:

202320222021 Estimated proved reserves values88 %83 %83 % Estimated proved reserves volumes: United States83 %80 %80 % Egypt80 %80 %80 % North Sea90 %81 %81 %

APA Worldwide83 %80 %80 % The Company has filed Ryder Scott's independent report as an exhibit to this Annual Report on Form 10-K. According to Ryder Scott's opinion, based on their review, including the data, technical processes, and interpretations presented by 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. 11

Business Combination with BCP On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination created an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. Pursuant to the BCP Contribution Agreement, Contributor contributed all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination). As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP's unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction closed during the first quarter of 2022. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. After the transaction closed, Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock. Upon closing the transaction, the Company no longer consolidated the assets and liabilities of ALTM in its consolidated financial statements. Subsequent to the close of the transaction, in March 2022, the Company sold four million of its 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.

Diversity and Inclusion 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.

Training and Development At APA, effective employee development integrates both training and performance management programs. In 2023, the Company continued to partner with local universities to provide business acumen courses for all employees. Classes were taught in-person as well as offered virtually for the Company's global and remote workforce. Additionally, several in-person and virtual classes on Oil & Gas 101 were rolled out to employees interested in understanding the basics of the industry. APA's Performance Management program moved into a more sustainable phase with a reinforcement on promoting an ongoing feedback culture between managers and employees.

Total Rewards APA's total rewards approach is designed to attract, motivate, and retain top talent by providing a robust compensation and benefits package that includes competitive base salary, industry-leading benefits and performance-driven incentives. To foster a stronger sense of ownership and align the interests of employees and shareholders, restricted stock units are provided to eligible employees under APA's broad-based compensation program. Furthermore, the Company offers comprehensive and locally relevant benefits that cultivate a family-friendly work environment and focus on the overall wellness of the Company's employees. In the U.S. these include, among other benefits: •Comprehensive health insurance coverage offered to employees working an average of 20 hours or more each week; •401(k) plan with up to an 8 percent Company match; •6 percent Company contributions to a money purchase retirement plan; •Company-paid short-term disability that pays a percentage of base pay according to years of service; •Parental leave for all new parents for birth and adoption; •Fertility and family building benefits to support the various paths to parenthood; •Elder care leave to temporarily care for or find permanent care for elder family members; 15 •Comprehensive mental health offering that includes access to mental health therapists or coaches, a learning platform that offers on-demand and interactive courses on mental health topics, and a library of well-being and self-care resources; and •Well-being program that encourages healthy habits and promotes physical, financial, social, and emotional well-being through webinars and challenges throughout the year.

Global Primary Workforce Safety Metrics Total Recordable Incident Rate (TRIR)(1) 0.2227% below target of 0.30 Days Away, Restricted and Transferred Rate (DART)(2)

United States 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.

(4)Vehicle Incident Rate (VIR): The rate of vehicle-related incidents per 1 million miles driven. Community Partnerships APA is committed to being socially and environmentally responsible in the communities where it operates. The Community Partnerships group oversees the Company's global strategic social investing and community engagement, including the stewardship of key stakeholder relationships. 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. •Community Well-being: APA continues to partner with organizations within the communities in which it operates to improve quality of life through access to education and essential medical supplies; development of innovative healthcare technologies and procedures; support for vulnerable populations, including women and children in need; response to natural disasters; and support for first responders. •Environmental Stewardship: In 2023, the Company's environmental stewardship initiatives included grants of 206,000 trees to 61 community partners through the Apache Corporation Tree Grant Program; continued partnership with the Texas Parks and Wildlife Foundation to provide sustainable funding for the restoration of Balmorhea State Park; and multi-year support of the Pecos Watershed Conservation Initiative, an alliance of seven energy companies, in partnership with the National Fish and Wildlife Foundation, to restore and protect natural grasslands and habitats within the greater Trans-Pecos Region. •Access to Energy: In 2023, the Company installed generators in the villages of Drietabbetje and Asidonhopo in the Surinamese Amazon, in partnership with the Surinamese Ministry of Natural Resources. The generators not only provide more reliable electricity for the two communities, but they will also help provide better quality health care, increased local trade, more educational opportunities and preserved Indigenous traditions. 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 16

Highlights of the Company's operations in the U.S. include: •Southern Midland Basin APA holds approximately 786,000 gross acres (450,000 net acres) in the Southern Midland Basin and the Eagle Ford shale and Austin Chalk areas of southeast Texas. During 2023, the Company primarily targeted oil plays in the Wolfcamp and Spraberry formations, drilling 69 gross development wells in this basin with a 100 percent success rate. •Delaware Basin APA holds approximately 233,000 gross acres (135,000 net acres) in the Delaware Basin, including opportunities in the Bone Spring and other formations of Eastern New Mexico and bordering West Texas, and the Alpine High play in the southern portion of the Permian Basin, primarily in Reeves County, Texas. During 2023, the Company drilled 57 gross development wells in this basin with a 100 percent success rate. 3 •Legacy Assets APA holds approximately 2.4 million gross acres (1.1 million net acres) in legacy properties, of which approximately 577,000 gross acres are in the offshore waters of the Gulf of Mexico. Consistent with the Company's broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings provide additional monetization opportunities that continue to be evaluated. •New Venture Assets APA separately has undeveloped acreage positions across several states, where it intends to pursue exploration interests and potential development opportunities over time. During the fourth quarter of 2023, the Company commenced an exploration program in Alaska, where it anticipates drilling three exploration wells in the first half of 2024. The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its three-year capital investment program. For 2024, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves. Future rig activity levels and drilling targets will be dependent on the success of the Company's drilling program and its ability to add reserves economically. U.S. Marketing The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. In addition, to satisfy a delivery commitment that began in 2023, the Company purchases third party natural gas to sell and deliver to a U.S. LNG export facility. The tenor of the Company's sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies, as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk. 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. U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 161 Bcf of natural gas per year for the period from 2024 through 2029, an average of 49 Bcf of natural gas per year for the period from 2030 through 2037, and an average of 4.9 MMbbls of crude oil per year for the period from 2024 through 2025, in each case, at variable, domestic and/or international, market-based pricing. 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.