The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025. Overview APA is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids (NGLs). The Company’s business has oil and gas exploration, development, appraisal, and/or ongoing operations primarily in four geographic areas: the U.S., Egypt, offshore the U.K. in the North Sea (North Sea), and offshore Suriname. APA also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its consolidated subsidiaries. APA believes energy underpins global progress, and the Company wants to be a part of the solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders. Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts and duration of armed conflicts involving the U.S., Iran, Russia, Ukraine, Israel, and other parties in the Middle East, inflation, current and potential tariffs or other trade barriers, global trade policies, and disputes, and actions taken by foreign oil and gas producing nations, including OPEC+. Despite these uncertainties, the Company is focused on its longer-term objectives: (1) to remain committed to providing affordable, reliable, and responsibly produced energy; (2) to deliver top operational performance across safety, environmental responsibility, execution, and risk management measures; (3) to maintain financial discipline by managing costs, protecting the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (4) to build and grow a diverse and balanced high-quality portfolio with scale through acquisitions, exploration, and organic opportunities. The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below. In the second quarter of 2026, the Company continued its cost reduction efforts to drive sustainable cost savings for the long-term. The Company remained focused on reducing overhead costs, improving the capital cost structure for its drilling, completions, and facility investments, and driving efficiencies of day-to-day field operating practices. The Company has raised its expected annualized savings target to $500 million by the end of 2026, an increase of $50 million from its previous guidance. The Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns. The Company believes returning 60 percent of free cash flow annually through dividends and share repurchases creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of continued balance sheet strengthening. •The Company pays a quarterly dividend of $0.25 per share on its common stock. •Beginning in the fourth quarter of 2021 and through the end of the second quarter of 2026, the Company has repurchased 101.0 million shares of the Company’s common stock. Subsequent to the quarter ended June 30, 2026 through July 31, 2026, the Company repurchased 0.3 million shares, and as of July 31, 2026, the Company had remaining authorization to repurchase up to 18.7 million shares under the Company’s share repurchase programs. •From year-end 2021 through the date of this filing, the Company has repaid $3.7 billion of long-term debt. 23 Financial and Operational Highlights In the second quarter of 2026, the Company reported net income attributable to common stock of $747 million, or $2.11 per diluted share, compared to net income of $603 million, or $1.67 per diluted share, in the second quarter of 2025. In the first six months of 2026, the Company reported net income attributable to common stock of $1.2 billion, or $3.37 per diluted share, compared to net income of $950 million, or $2.62 per diluted share, in the first six months of 2025. The increase in net income in the second quarter and the first six months of 2026, compared to the second quarter and first six months of 2025, was primarily driven by higher oil revenues on stronger crude oil price realizations, improved margins on third-party purchased oil and gas activity and lower operating expenses driven by prior-year cost savings initiatives. The Company generated $2.3 billion of cash from operating activities during the first six months of 2026, remaining flat when compared to the first six months of 2025. The Company paid $177 million in dividends to APA common stockholders and repurchased approximately $100 million of Company common stock during the first six months of 2026. The Company also repaid $752 million of long-term debt principal during the first six months of 2026. Key operational highlights include: United States •Daily boe production from the Company’s U.S. assets, which decreased 9 percent from the second quarter of 2025, accounted for 64 percent of the Company’s worldwide production during the second quarter of 2026. The Company averaged five drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and one rig in the Delaware Basin in the second quarter of 2026. The Company brought online 47 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent a key area for the U.S. assets. •APA holds approximately 750,000 MMBtu/d of firm capacity on various pipelines in the Permian Basin. As of June 30, 2026, the Company had open basis swap contracts which purchased Waha and sold NYMEX Henry Hub on approximately one-third of its firm transport capacity for 2026, thereby locking in a significant portion of cash flows associated with its gas trading activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements. •During the second quarter of 2026, the Company entered into an agreement to acquire Savant Alaska, LLC for approximately $70 million in upfront consideration, plus contingent payments tied to future development of the Company’s Alaska position. The to-be acquired infrastructure is expected to support operations beginning with 2026-2027 exploration and appraisal activities, while enhancing future development flexibility. Upon closing, the transaction is expected to add approximately 104,000 gross acres and approximately 1,500 b/d of oil production. The transaction is expected to close by year-end 2026. International •In Egypt, the Company averaged 12 drilling rigs and drilled 11 new productive wells during the second quarter of 2026. The Company also averaged 18 workover rigs as it continues optimizing drilling and workover activity for capital efficiency. Second quarter 2026 gross production from the Company’s Egypt assets increased 2 percent while net production decreased 13 percent from the second quarter of 2025. Second quarter 2026 net production was negatively impacted by higher price realizations and lower cost recovery volumes under the merged concession agreement. •In Egypt, the Company expects approximately one-half of its rig activities to continue to be gas-focused and anticipates continued strong performance for the rest of the year, with realized gas prices increasing through the period. •During the quarter, the Government of Egypt awarded the Company a five-year extension covering approximately 3.4 million acres of exploration acreage that was otherwise set to expire. In addition, approximately 400,000 acres of non-prospective acreage was not renewed in accordance with the applicable concession agreement terms. In connection with the extension, the Company committed to a drilling and seismic acquisition and reprocessing program, which it expects to complete in the normal course of operations. •In Uruguay, the Company signed an agreement with Eni S.p.A. as a strategic partner in offshore Block 6. The Company will retain a 60 percent working interest, with Eni funding most of the initial exploration well planned for 2027. 24 Results of Operations Oil, Natural Gas, and Natural Gas Liquids Production Revenues Revenue The Company’s production revenues and respective contribution to total revenues by country were as follows: For the Quarter EndedJune 30, For the Six Months Ended June 30, 2026 2025 2026 2025 $ Value % Contribution $ Value % Contribution $ Value % Contribution $ Value % Contribution ($ in millions) Oil Revenues: United States $ 1,106 61 % $ 730 53 % $ 1,915 55 % $ 1,546 52 % Egypt(1) 613 33 % 521 38 % 1,284 37 % 1,103 37 % North Sea 107 6 % 130 9 % 271 8 % 332 11 % Total(1) $ 1,826 100 % $ 1,381 100 % $ 3,470 100 % $ 2,981 100 % Natural Gas Revenues: United States $ (109) (266) % $ 48 26 % $ (121) (61) % $ 152 36 % Egypt(1) 126 307 % 109 59 % 264 133 % 200 48 % North Sea 24 59 % 27 15 % 55 28 % 65 16 % Total(1) $ 41 100 % $ 184 100 % $ 198 100 % $ 417 100 % NGL Revenues: United States $ 161 95 % $ 144 94 % $ 290 93 % $ 340 95 % North Sea 9 5 % 9 6 % 21 7 % 19 5 % Total(1) $ 170 100 % $ 153 100 % $ 311 100 % $ 359 100 % Oil and Gas Revenues: United States $ 1,158 57 % $ 922 54 % $ 2,084 52 % $ 2,038 54 % Egypt(1) 739 36 % 630 37 % 1,548 39 % 1,303 35 % North Sea 140 7 % 166 9 % 347 9 % 416 11 % Total(1) $ 2,037 100 % $ 1,718 100 % $ 3,979 100 % $ 3,757 100 % (1) Includes revenues attributable to a noncontrolling interest in Egypt. 25 Production The Company’s production volumes by country were as follows: For the Quarter EndedJune 30, For the Six Months EndedJune 30, 2026 Increase (Decrease) 2025 2026 Increase (Decrease) 2025 Oil Volume (b/d) United States 123,455 —% 123,725 123,675 (1)% 124,420 Egypt(1)(2) 70,139 (19)% 86,210 78,392 (9)% 86,192 North Sea 17,676 (30)% 25,309 19,496 (23)% 25,258 Total 211,270 (10)% 235,244 221,563 (6)% 235,870 Natural Gas Volume (Mcf/d) United States 403,474 (22)% 519,276 408,696 (25)% 546,853 Egypt(1)(2) 327,286 (5)% 345,649 354,196 7% 331,507 North Sea 21,365 (27)% 29,174 25,184 (17)% 30,383 Total 752,125 (16)% 894,099 788,076 (13)% 908,743 NGL Volume (b/d) United States 72,487 (9)% 79,632 72,158 (8)% 78,525 North Sea 848 (28)% 1,186 999 (14)% 1,165 Total 73,335 (9)% 80,818 73,157 (8)% 79,690 BOE per day(3) United States 263,187 (9)% 289,902 263,949 (10)% 294,087 Egypt(1)(2) 124,687 (13)% 143,818 137,425 (3)% 141,443 North Sea(4) 22,085 (30)% 31,358 24,692 (22)% 31,487 Total 409,959 (12)% 465,078 426,066 (9)% 467,017 (1) Gross production volumes in Egypt were as follows: For the Quarter Ended June 30, For the Six Months Ended June 30, 2026 2025 2026 2025 Oil (b/d) 117,056 123,852 119,252 125,927 Natural Gas (Mcf/d) 538,925 479,235 528,333 468,157 (2) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of: For the Quarter Ended June 30, For the Six Months Ended June 30, 2026 2025 2026 2025 Oil (b/d) 23,386 28,762 26,138 28,754 Natural Gas (Mcf/d) 109,125 115,319 118,100 110,596 (3) 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. (4) Average sales volumes from the North Sea for the second quarters of 2026 and 2025 were 14,877 boe/d and 28,015 boe/d, respectively, and 21,539 boe/d and 32,336 boe/d for the first six months of 2026 and 2025, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings. 26 Pricing The Company’s average selling prices by country were as follows: For the Quarter EndedJune 30, For the Six Months EndedJune 30, 2026 Increase (Decrease) 2025 2026 Increase (Decrease) 2025 Average Oil Price – Per barrel United States $ 98.46 52% $ 64.84 $ 85.54 25% $ 68.64 Egypt 95.95 45% 66.39 90.48 28% 70.70 North Sea 110.78 66% 66.56 93.36 30% 71.61 Total 98.24 50% 65.58 87.89 26% 69.72 Average Natural Gas Price – Per Mcf United States $ (2.98) (389)% $ 1.03 $ (1.64) (206)% $ 1.54 Egypt 4.23 22% 3.48 4.12 23% 3.34 North Sea 15.88 36% 11.69 14.89 11% 13.42 Total 0.60 (74)% 2.28 1.39 (45)% 2.55 Average NGL Price – Per barrel United States $ 24.59 24% $ 19.87 $ 22.26 (7)% $ 23.91 North Sea 67.50 62% 41.62 55.59 20% 46.28 Total 25.41 24% 20.49 23.19 (6)% 24.54 Second-Quarter 2026 compared to Second-Quarter 2025 Crude Oil Crude oil revenues for the second quarter of 2026 totaled $1.8 billion, a $445 million increase from the comparative 2025 quarter. A 50 percent increase in average realized prices increased second-quarter 2026 oil revenues by $688 million compared to the second quarter of 2025, while 10 percent lower average daily sales volumes decreased revenues by $243 million. Crude oil accounted for 90 percent of total oil and gas production revenues and 52 percent of worldwide production in the second quarter of 2026. Crude oil prices realized during the second quarter of 2026 averaged $98.24 per barrel, compared to $65.58 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 24.0 Mb/d to 211.3 Mb/d during the second quarter of 2026 from the comparative prior-year period, primarily a result of the sale of non-core assets, natural production decline in the U.S. and North Sea, and operational downtime in the North Sea. Second quarter 2026 net production in Egypt was negatively impacted by higher price realizations and lower cost recovery volumes under the merged concession agreement. These decreases were partially offset by successful drilling activity in the Permian Basin. Natural Gas Natural gas revenues for the second quarter of 2026 totaled $41 million, a $143 million decrease from the comparative 2025 quarter. A 74 percent decrease in average realized prices, driven by periods of negative pricing across the Permian Basin, decreased second-quarter 2026 natural gas revenues by $135 million compared to the second quarter of 2025, while 16 percent lower average daily production decreased gas revenues by $8 million. Natural gas accounted for 2 percent of total oil and gas production revenues and 31 percent of worldwide production during the second quarter of 2026. The Company’s worldwide natural gas production decreased 142.0 MMcf/d to 752.1 MMcf/d during the second quarter of 2026 from the comparative prior-year period, primarily a result of increased volume curtailments at Alpine High compared with the 2025 period in response to extreme Waha basis differentials, including periods of negative pricing. These curtailments were undertaken to mitigate the economic impact of selling gas into constrained markets at uneconomic or negative prices. Natural gas production was also lower as a result of the sale of non-core assets in the U.S., and operational downtime in the North Sea. NGL NGL revenues for the second quarter of 2026 totaled $170 million, a $17 million increase from the comparative 2025 quarter. A 24 percent increase in average realized prices increased second-quarter 2026 NGL revenues by $36 million compared to the second quarter of 2025, while 9 percent lower average daily production decreased revenues by $19 million. NGLs accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production during the second quarter of 2026. 27 The Company’s worldwide NGL production decreased 7.5 Mb/d to 73.3 Mb/d during the second quarter of 2026 from the comparative prior-year period, primarily a result of increased volume curtailments compared with the 2025 period in response to extreme negative price basis differentials in the Permian Basin. NGL production was also lower as a result of the sale of non-core assets in the U.S., and operational downtime in the North Sea. Year-to-Date 2026 compared to Year-to-Date 2025 Crude Oil Crude oil revenues for the first six months of 2026 totaled $3.5 billion, a $489 million increase from the comparative 2025 period. A 26 percent increase in average realized prices for the 2026 period increased oil revenues by $777 million compared to the prior-year period, while 6 percent lower average daily production decreased oil revenues by $288 million compared to the prior-year period. Crude oil revenues accounted for 87 percent of total oil and gas production revenues and 52 percent of worldwide production for the first six months of 2026. Crude oil prices realized during the first six months of 2026 averaged $87.89 per barrel, compared to $69.72 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 14.3 Mb/d to 221.6 Mb/d in the first six months of 2026 compared to the prior-year period, primarily a result of the sale of non-core assets and weather shut-ins in the U.S., operational downtime in the North Sea, and natural production decline across all assets. These decreases were partially offset by successful drilling activity in the Permian Basin. Natural Gas Natural gas revenues for the first six months of 2026 totaled $198 million, a $219 million decrease from the comparative 2025 period. A 45 percent decrease in average realized prices, driven by periods of negative pricing across the Permian Basin, decreased natural gas revenues for the 2026 period by $189 million compared to the prior-year period, while 13 percent lower average daily production decreased revenues by $30 million compared to the prior-year period. Natural gas revenues accounted for 5 percent of total oil and gas production revenues and 31 percent of worldwide production for the first six months of 2026. The Company’s worldwide natural gas production decreased 120.7 MMcf/d to 788 MMcf/d in the first six months of 2026 compared to the prior-year period, primarily a result of increased volume curtailments at Alpine High in response to extreme Waha basis differentials , including periods of negative pricing. Natural gas production was also lower as a result of the sale of non-core assets in the U.S., and operational downtime in the North Sea. NGL NGL revenues for the first six months of 2026 totaled $311 million, a $48 million decrease from the comparative 2025 period. An 8 percent lower average daily production decreased NGL revenues for the 2026 period by $28 million compared to the prior-year period, while a 6 percent decrease in average realized prices decreased revenues by $20 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production for the first six months of 2026. The Company’s worldwide NGL production decreased 6.5 Mb/d to 73.2 Mb/d in the first six months of 2026 compared to the prior-year period, primarily a result of increased volume curtailments in response to negative basis differentials in the Permian Basin and the sale of non-core assets in the U.S. These decreases were partially offset by less ethane rejection in the U.S. compared to the same prior-year period. Purchased Oil and Gas Sales Purchased oil and gas sales represent volumes attributable to domestic oil and gas purchases that were sold by the Company primarily to fulfill oil and natural gas takeaway obligations and pipeline commitments, including deliveries under international LNG price-based contracts. Sales related to purchased volumes totaled $336 million and $460 million during the second quarters of 2026 and 2025, respectively, and $721 million and $1.1 billion during the first six months of 2026 and 2025, respectively. Associated purchase costs for the sales volumes resulted in net proceeds received totaling $122 million and $47 million for the second quarter and the first six months of 2026, respectively. Associated purchases costs for sales volumes for the second quarter and the first six months of 2025 were $304 million and $778 million, respectively. The higher margin between purchased volume sales and costs realized during the second quarter and the first six months of 2026 was primarily attributable to extreme Permian Basin natural gas prices, which included periods of negative pricing, compared with Houston Ship Channel pricing. 28 Operating Expenses The Company’s operating expenses were as follows and include costs attributable to a noncontrolling interest in Egypt: For the Quarter EndedJune 30, For the Six Months EndedJune 30, 2026 2025 2026 2025 (In millions) Lease operating expenses $ 353 $ 367 $ 715 $ 774 Gathering, processing, and transmission 87 104 178 208 Purchased oil and gas costs (proceeds) (122) 304 (47) 778 Taxes other than income 61 54 118 128 Exploration 58 43 84 73 General and administrative 68 66 183 164 Transaction, reorganization, and separation 12 11 19 48 Depreciation, depletion, and amortization: Oil and gas property and equipment 497 523 1,043 1,159 Other assets 7 7 14 14 Asset retirement obligation accretion 43 39 85 78 Financing costs, net 58 66 115 9 Total Operating Expenses $ 1,122 $ 1,584 $ 2,507 $ 3,433 Lease Operating Expenses (LOE) LOE decreased $14 million and $59 million from the second quarter and the first six months of 2025, respectively. On a per-unit basis, LOE increased 10 percent and 2 percent in the second quarter and the first six months of 2026, respectively, when compared to the second quarter and the first six months of 2025. The decrease in overall absolute costs was primarily driven by the sale of non-core assets in the Permian Basin, timing of liftings in the North Sea, and continued cost reduction efforts across all operating areas. Gathering, Processing, and Transmission (GPT) GPT costs decreased $17 million and $30 million from the second quarter and the first six months of 2025, respectively, primarily driven by a decrease in production volumes in the U.S. compared to the same prior-year period. Purchased Oil and Gas Costs (Proceeds) Purchased oil and gas costs decreased $426 million and $825 million from the second quarter and the first six months of 2025, respectively, primarily driven by gas volumes purchased at significantly lower prices in the Permian Basin, including periods of realized negative prices, and decreased oil and gas volume purchases following the expiration of certain third-party contracts in 2025. Periods of negative gas pricing during 2026 in the Permian Basin resulted in the Company receiving net proceeds totaling $122 million and $47 million during the second quarter and the first six months of 2026, respectively. Taxes Other Than Income Taxes other than income increased $7 million and decreased $10 million from the second quarter and the first six months of 2025, respectively. The increase in taxes for the second quarter of 2026 was driven by higher severance taxes associated with higher oil and NGL prices in the U.S., partially offset by lower ad valorem taxes. The decrease in taxes for the first six months of 2026 was primarily due to lower ad valorem taxes, partially offset by higher severance taxes driven by higher oil prices in the U.S. 29 Exploration Expenses The Company’s exploration expenses were as follows: For the Quarter EndedJune 30, For the Six Months EndedJune 30, 2026 2025 2026 2025 (In millions) Unproved leasehold impairments $ 1 $ — $ 2 $ — Dry hole expense 43 32 54 43 Geological and geophysical expense 2 — 4 4 Exploration overhead and other 12 11 24 26 Total Exploration $ 58 $ 43 $ 84 $ 73 Exploration expenses increased $15 million and $11 million from the second quarter and the first six months of 2025, respectively, primarily the result of higher dry hole expense in Egypt compared to the same prior-year periods. General and Administrative (G&A) Expenses G&A expenses increased $2 million and $19 million from the second quarter and the first six months of 2025, respectively, primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price during the periods, partially offset by impacts from cost-reduction efforts on personnel and other overhead expenses. Transaction, Reorganization, and Separation (TRS) Costs TRS costs increased $1 million and decreased $29 million from the second quarter and the first six months of 2025, respectively. TRS costs in the second quarter of 2026 were primarily related to transaction costs incurred during the quarter. The decrease in TRS costs in the first six months of 2026 was driven by employee separations and other cost-saving initiatives that occurred during the first six months of 2025. Depreciation, Depletion, and Amortization (DD&A) Total DD&A expenses decreased $26 million and $116 million from the second quarter and the first six months of 2025, respectively. The Company’s DD&A rate on its oil and gas properties increased $1.11 and decreased $0.05 per boe from the second quarter and the first six months of 2025, respectively. The decrease in DD&A expense on an absolute basis for the second quarter of 2026 was primarily driven by lower production volumes. This decrease was partially offset by higher DD&A rates resulting from negative gas price-related reserve revisions in the U.S. Permian Basin. For the first six months of 2026, the decrease in DD&A absolute expenses and on a per boe basis was primarily due to lower DD&A rates driven by lower production volumes resulting from the sale of non-core assets in the Permian Basin. Financing Costs, Net The Company’s Financing costs were as follows: For the Quarter EndedJune 30, For the Six Months EndedJune 30, 2026 2025 2026 2025 (In millions) Interest expense $ 69 $ 86 $ 139 $ 177 Amortization of debt issuance costs 1 2 2 4 Capitalized interest (16) (16) (30) (20) Gain on extinguishment of debt 4 (3) 4 (145) Interest income — (3) — (7) Total Financing costs, net $ 58 $ 66 $ 115 $ 9 Net financing costs decreased $8 million and increased $106 million from the second quarter and the first six months of 2025, respectively. The decrease in net financing costs in the second quarter of 2026 was driven by lower interest expense, a result of lower outstanding debt balances compared to the same prior-year period. Higher net financing costs during the first six months of 2026 was the result of gains on extinguishment of debt from the Company’s cash tender purchases during the first six months of 2025, partially offset by a decrease in interest expense from the associated lower long-term debt balance. 30 Provision for Income Taxes The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur. The Company’s effective income tax rate for the six months ended June 30, 2026 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. The Company’s effective income tax rate for the six months ended June 30, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for corporate alternative minimum tax (CAMT) purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2026, as impacts to current tax expense are offset by impacts to deferred tax expense. The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. Capital Resources and Liquidity Operating cash flows are the Company’s principal source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. The Company expects commodity prices to continue to be volatile in the near term as a result of geopolitical instability and tensions, including in the Middle East, macroeconomic uncertainty, current and potential tariffs or trade barriers, supply chain disruptions, and concerns over a potential economic recession. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term. The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. At this time, the Company is unable to predict to what extent ongoing international conflicts in the Middle East, Russia, and Ukraine, and potential changes in trade restrictions and tariffs will impact its business. If inflationary pressures from these and other economic conditions persist or worsen, the Company may incur additional operating costs. The Company will continue to monitor the impact and consequences of these factors on its operations. The Company expects to invest approximately $2.1 billion in upstream capital investment in 2026. The Company is committed to maintaining a safe and efficient level of activity as part of its planned capital investment program. For the rest of 2026, 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, subject to prevailing commodity prices. 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. The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies. 31 The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs. For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025. Sources and Uses of Cash The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented: For the Six Months EndedJune 30, 2026 2025 (In millions) Sources of Cash and Cash Equivalents: Net cash provided by operating activities $ 2,260 $ 2,277 Fixed-rate debt borrowings — 846 Proceeds from asset divestitures — 571 Total Sources of Cash and Cash Equivalents 2,260 3,694 Uses of Cash and Cash Equivalents: Additions to upstream oil and gas property $ 1,111 $ 1,437 Leasehold and property acquisitions 6 20 Payments on commercial paper and revolving credit facilities, net — 333 Payments on term loan facility — 900 Payments on fixed-rate debt 754 954 Dividends paid to APA common stockholders 177 181 Distributions to noncontrolling interest 164 217 Treasury stock activity, net 100 150 Other, net 20 20 Total Uses of Cash and Cash Equivalents 2,332 4,212 Decrease in Cash and Cash Equivalents $ (72) $ (518) Sources of Cash and Cash Equivalents Net Cash Provided by Operating Activities Operating cash flows are the Company’s principal 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 accretion, and deferred income tax expense. Net cash provided by operating activities during the first six months of 2026 totaled $2.3 billion, $17 million lower than the first six months of 2025. 2026 benefited from higher oil and gas revenues from higher realized oil prices and higher margins on third-party purchased oil and gas sales. 2025 benefitted from the collection of outstanding Egypt receivables and timing of other working capital items. For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. 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 I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q. Uses of Cash and Cash Equivalents Additions to Oil & Gas Property During the first six months of 2026 and 2025, exploration and development cash expenditures were $1.1 billion and $1.4 billion, respectively. The decrease in capital investment compared to the prior-year period is largely driven by the Company’s efficiency gains on drilling and completion activities in the Permian Basin and Egypt. The Company operated an average of approximately 17 drilling rigs during the first six months of 2026, compared to an average of approximately 21 drilling rigs during the first six months of 2025. 32 Leasehold and Property Acquisitions During the first six months of 2026 and 2025, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $6 million and $20 million, respectively. Payments on Fixed-Rate Debt During the first six months of 2026, the Company repaid in cash $754 million of long-term debt, which comprised outstanding principal amounts and make-whole premiums, plus accrued and unpaid interest. During the first six months of 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures of Apache and made open market repurchases for an aggregate cash payment amount of $954 million, reflecting principal amounts, discount to par, and associated fees. The Company may, and expects that Apache will continue to, reduce debt outstanding under its indentures from time to time. Dividends Paid to APA Common Stockholders During the first six months of 2026 and 2025, the Company paid $177 million and $181 million, respectively, for dividends on its common stock. Distributions to Noncontrolling Interest Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. During the first six months of 2026 and 2025, the Company paid $164 million and $217 million, respectively, in cash distributions to Sinopec. Treasury Stock Activity, net In the first six months of 2026, the Company repurchased 2.8 million shares at an average price of $35.26 per share and an aggregate purchase price of approximately $100 million, and as of June 30, 2026, the Company had remaining authorization to repurchase 19.0 million shares. In the first six months of 2025, the Company repurchased 7.1 million shares at an average price of $21.21 per share and an aggregate purchase price of approximately $150 million. Liquidity The following table presents a summary of the Company’s key financial indicators: June 30,2026 December 31,2025 (In millions) Cash and cash equivalents $ 444 $ 516 Total debt – APA and Apache 3,743 4,493 Total equity 7,944 7,003 Available committed borrowing capacity under syndicated credit facilities 3,989 4,020 Cash and Cash Equivalents As of June 30, 2026, the Company had $444 million in cash and cash equivalents. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase. Debt As of June 30, 2026, the Company had $3.7 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache and finance lease obligations. As of June 30, 2026, current debt included $2 million of finance lease obligations. Indenture Debt Activity On June 29, 2026, APA fully redeemed its privately placed 4.250% Notes due 2030, and Apache fully redeemed its 4.250% Notes due 2030. Noteholders were paid an aggregate $118 million in cash, which comprised outstanding principal amounts, plus accrued and unpaid interest to the redemption date. On April 15, 2026, APA and Apache repaid in cash on maturity the outstanding $132 million aggregate principal amount of their respective 7.95% Notes due 2026, plus accrued and unpaid interest to the maturity date. On April 6, 2026, APA and Apache fully redeemed their respective 4.875% Notes due 2027 and 4.375% Notes due 2028. Noteholders were paid an aggregate $425 million in cash, which comprised outstanding principal amounts and make-whole premiums, plus accrued and unpaid interest to the redemption date. On March 15, 2026, APA and Apache repaid in cash on maturity the outstanding $79 million aggregate principal amount of their respective 7.70% Notes due 2026, plus accrued and unpaid interest to the maturity date. 33 During the six months ended June 30, 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $108 million for an aggregate purchase price of $100 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $10 million gain on these repurchases. On January 10, 2025, APA settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. In settling these offers pursuant to their respective terms, APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. The Company recognized a gain of $135 million on these purchases, including broker fees and loan costs. Committed Credit Facilities On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes: •One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company’s two, one-year extension options. •The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company’s two, one-year extension options. As of June 30, 2026, there were no borrowings or letters of credit outstanding under the USD Agreement or the GBP Agreement. As of December 31, 2025, there were no borrowings or letters of credit outstanding under the USD Agreement and no borrowings and an aggregate £1.0 million in letters of credit outstanding under the GBP Agreement. Uncommitted Lines of Credit Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, 2026 and December 31, 2025, there were no outstanding borrowings under these facilities. As of June 30, 2026, there were £567 million and $10 million in letters of credit outstanding under these facilities. As of December 31, 2025, there were £901 million and $10 million in letters of credit outstanding under these facilities. Commercial Paper Program The Company has a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $2.0 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed revolving credit facilities for general corporate purposes, which as of June 30, 2026, included the $2.0 billion USD Agreement. The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance. As of each of June 30, 2026 and December 31, 2025, the Company had no CP Notes outstanding. Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025. There have been no material changes to the contractual obligations described therein. 34 Potential Decommissioning Obligations on Sold Properties In 2013, Apache sold its Gulf of America (GOA) Shelf operations and properties and its GOA operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). 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 GOA Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOA 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 GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA Assets. The decommissioning obligations for the Legacy GOA Assets are partially secured by a trust account of which Apache is a beneficiary and which is funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to loan GOM Shelf of up to $400 million to perform decommissioning, with such loans and related obligations secured by first and prior liens on the Legacy GOA Assets. By letter dated April 5, 2022 (replacing two earlier letters) 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 was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOA 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 GOA Assets. As of June 30, 2026, the Company has recorded an asset of $41 million, representing the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs. The Company has also recorded contingent liabilities in the amounts of $847 million and $881 million for the periods ended June 30, 2026 and December 31, 2025, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOA Assets. There have been no other changes in estimates from December 31, 2025 that would have a material impact on the Company’s financial position, results of operations, or liquidity.