APA 10-K & 10-Q changes, risk factors and insider trading

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

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 20242025 ranged from a high of $87.69$80.73 per barrel to a low of $66.73$55.44 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 20242025 ranged from a high of $13.20$9.86 per MMBtu to a low of $1.21$2.65 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:

•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 Gazaconflicts;

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

The Company’s ability to sell crude oil, natural gas, or NGLs, receive market prices for these commodities, and/or meet volume commitments under transportation services agreementsagreements, and/or economically market third-party volumes may be adversely affected by pipeline and gathering system capacity constraints,changes, the inability to procure and resell volumes economically, and various transportation interruptions.interruptions or expansions, and the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.

A portion of the Company’s crude oil, natural gas, and NGL production in any region may be, and previously have been, interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, cyberattacks or terrorist events, or capital constraintsconstraints, financial distress, or insolvency of third-party providers that limit the ability of such third parties to construct gathering systems, processing facilities, or interstate pipelines to transport the Company’s production. Additionally, the Company has previously and may in the future voluntarily curtail production in response to market conditions, such as weak or negative prices. If a substantial amount of the Company’s production is interrupted or curtailed at the same time, it could temporarily adversely affect the Company’s cash flows. Further, if the Company is unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, the Company’s cash flows could be adversely affected. As additional gas pipeline takeaway capacity in the Permian Basin comes online, the spread between Permian and Gulf Coast gas prices may compress, which would reduce the Company’s gain on third-party oil and gas purchases and sales.

The Company’s commodity price and other risk management and trading activitiesactivities, including interest rate and foreign exchange hedging, and contracts priced in foreign currencies may prevent it from benefiting fully from price increases and market movements and may expose it to other risks.

To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases. Similarly, to the extent the Company enters into derivative contracts to manage exposure to interest rate or foreign exchange risk or enters into contracts priced in a foreign currency, it may be limited in its ability to benefit from favorable movements in interest rates or currency exchange rates or may incur additional expense converting to a foreign currency to fund contractual obligations. The Company’s hedging arrangements may expose it to the risk of financial loss, including when production falls short of the hedged volumes, price-basis differentials widen, a hedging counterparty defaults, or an unexpected event materially impacts commodity prices. In addition, because the Company does not apply hedge accounting to its derivative instruments, changes in the fair value of derivatives are recognized in current-period earnings, which may introduce earnings volatility even when the underlying exposure is intended to be economically hedged.

GlobalPublic pandemicshealth events, workforce disruptions, or similar global or regional events have previously, may continue to,previously and may in the future adversely impact the Company’s business, financial condition, and results of operations; the global economy; the demand for and prices of oil, natural gas, and NGLs; and the performance of the Company’s workforce.operations.

RISKS RELATED TO OPERATIONSOPERATIONS, SAFETY, AND EXPLORATION AND DEVELOPMENT PROJECTS

The Company expendsmay significantbe required to expend further resources to protect its digital systems and data, whether such data is housed internally or externally by third parties, against cyberattacks and may be required to expend further resources as cyber threat actors become more sophisticated and as regulations related to cyberattacks become more complex. Cyberattacks, including malicious software, data privacy breaches by employees, insiders, or others with authorized access to the Company’s systems, cyber or phishing attacks, ransomware attacks, supply chain vulnerabilities, business email compromises, other attempts to gain unauthorized access to the Company’s data and systems, and other electronic security breaches could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.

While the Company has not suffered any material losses as a result of cyberattacks, there is no assurance that the Company will not suffer such losses in the future. See Item 1C—Cybersecurity for additional information regarding the Company’s cybersecurity risk management and governance.

The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturingcost inflation, availability, manufacturing, and delivery schedules of critical vessels and equipment, customs and logistics, cash-call timing or funding shortfalls, and other unforeseen events. Delays and differences between estimated and actual timing of critical events and development costs (including for equipment and personnel) may adversely affect the Company’s large development projects (including forcing the Company to abandon such projects) and its ability to participate in large-scale development projects in the future.

RISKS RELATED TO RESERVESRESERVES, ESTIMATES, AND LEASEHOLD ACREAGELEASEHOLDS

There are numerous uncertainties inherent in the process of estimating crude oil, natural gas, and NGL reserves and their value, which is highly subjective and relies on the quality of available data and the accuracy of engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist, causingconsistent reserveswith quantitiesapplicable toSEC changepricing whenand actualreporting rules. Therefore, changes in future commodity prices increase or decrease.in development plans can materially impact reported reserves. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including historical production from the area compared with production from other areas, the results of drilling, testing, and production for a reservoir over time, the use of volumetric analysis versus production history, the effects of changes in laws (including emissions regulations, infrastructure modernization requirements, and taxes), future operating, workover, and remediation costs, and capital expenditures. For example, during 2024, the Company recorded $796 million of impairments for certain of its North Sea proved properties as a result of several new regulatory guidelines and obligations in the U.K. Accordingly, reserves estimates may be subject to adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

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

RISKS RELATED TO COUNTERPARTIES AND JOINT VENTURES

The Company conducts many of its exploration and production (E&P) operations through joint operating agreements or joint ventures with other parties.parties, including state-owned or government-controlled entities. The Company may not control decisions made under such agreements or ventures, either because it does not have a controlling interest in the venture or is not an operator under the agreement. The other parties to these arrangements may have economic, business, or legal interests or goals that are inconsistent with the Company’s, and,including therefore,priorities set by governmental or state-owned counterparties, or that are influenced by governmental policy, fiscal priorities, or broader economic or social conditions, which may affect decision making, capital allocation, payment timing, or operational approvals. Therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to such agreements or ventures may be unable to meet their economic or other obligations, and the Company may be required to fulfill those obligations alone. In either case, the value of the investment and the Company’s business and financial condition may be adversely affected.

RISKS RELATED TO CAPITAL MARKETSMARKETS, LIQUIDITY, AND TAX MATTERS

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 2024, Standard and Poor’s upgraded the Company’s rating to BBB-/Stable, Moody’s affirmed the Company’s rating at Baa3/Stable, and Fitch affirmed the Company’s rating at BBB-/Stable. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.

The financial markets are subject to fluctuation and are vulnerable to unpredictable swings. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company’s future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained.constrained or if financial institutions, investors, or insurers limit exposure to oil and gas companies or modify underwriting standards in response to climate-related or other policy developments. This could significantly delay development of the Company’s property interests.

RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKSMATTERS

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

Federal, state, and foreign income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. For example, the U.K. enacted the Energy Profits Levy (EPL), which assesses(prior to recent law changes) assessed an additional levy of 35 percent, effective for the period of January 1, 2023, through March 31, 2028, on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Further changes to the EPL regime were announced in 2024, with enactment expectedenacted in 2025. Such changes, effective for the period of November 1, 2024, through March 31, 2030, would increaseincreased the levy to 38 percent, removeremoved certain allowances, and extendextended the EPL period. Additionally, in the U.S., the Inflation Reduction Act of 2022 introduced a new 15 percent corporate alternative minimum tax (Corporate AMT) for taxable years beginning after December 31, 2022, on applicable corporations with an average annual adjusted financial statement income (AFSI) that exceeds $1.0 billion for any three consecutive tax years preceding the tax year at issue. Effective January 1,During 2024, the Company isperformed subjectan economic assessment of its North Sea assets in light of the significant tax levies, along with several new regulatory guidelines and obligations surrounding modernization of aging infrastructure, and determined that expected returns did not economically support making investments required under the combined impact of the regulations and now expects to thecease Corporateproduction AMT.at Accordingly,its anyfacilities resulting Corporate AMT liability could adversely affectin the Company’sNorth futureSea financialprior results,to including earnings and cash flows.2030.

RISKS RELATED TO CLIMATE CHANGECHANGE, ENERGY TRANSITION, AND ESG MATTERS

The impacts of climate change, energy transition policies, and ESG-related initiatives could adversely affect the Company’s business, operating results, and financial condition.

InAttention recentcontinues years,to increasing attention has beenbe 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,with or powered by,by hydrocarbons, mayhave resultresulted 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.

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

Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company’s operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company’s cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including previous discussion in the U.S.,U.S. when the regulatory landscape at the federal level was more focused on these issues, regarding changes in legislation or heightened regulation of GHGs, including to monitor and limit existing emissions of GHGs andGHGs, to restrict or eliminate future emissions.emissions, Moreover, in January 2024, the EPA announced a proposed ruleor to assess a charge on certain methane emissions in the oil and gas industry. TheAdditionally, Companyvarious isstates currentlyand evaluatinggroups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the proposedCompany’s ruleoperations andcould its applicabilitylead to increased operating expenses or cause the Company and is monitoring ongoing litigation related to themake proposedsignificant rule.capital investments for infrastructure modifications.

Given the dynamic nature of the Company’s business, the Company generally performs annualbiennial 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.reports. 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.

Uncertainties in the global supply chain and financial markets,markets includingimpact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impactimpacts of ongoing international conflicts, 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+, impact oil supply and demand and contribute to commodity price volatility.. Despite these uncertainties, the Company remainsis committedfocused toon its longer-term objectives: (1) to investremain forcommitted long-termto returnsproviding inaffordable, pursuitreliable, ofand moderate,responsibly sustainableproduced production growthenergy; (2) to strengthendeliver 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 (34) to responsiblybuild manageand itsgrow costa structurediverse regardlessand ofbalanced thehigh-quality oilportfolio pricewith environment.scale through acquisitions, exploration, and organic opportunities.

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

•The Company payspaid a quarterly dividend of $0.25 per share on its common stock.stock during 2025.

•Beginning in the fourth quarter of 2021 and through the end of 2024,2025, the Company has repurchased 85.398.2 million shares of the Company’s common stock. Subsequent to year-end 2024 and through the dateAs of thisDecember filing on February 28, 2025, the Company repurchased 3.9 million shares, and as of February 28,31, 2025, the Company had remaining authorization to repurchase up to 30.921.9 million shares under the Company’s share repurchase programs.program.

During 2024,2025, the Company reported net income attributable to common stock of $804$1.4 million,billion, or $2.27$3.99 per diluted share, compared to net income of $2.9$804 billion,million, or $9.25$2.27 per diluted share, in 2023.2024. NetThe increase in net income induring 20242025 was primarily impactedthe result of by impairments$1.1 billion of $1.1impairments billion,recorded in 2024, which included oil and gas property impairments of $796 million in the North Sea and $315 million in the U.S., and lower realized crude oil and natural gas prices during the year compared to 2023.U.S. The Company also recorded higher oil and gas revenues and associatedlower operating expenses resultingin from2025 compared to the Callonprior-year acquisition.period, the result of focused cost-reduction efforts undertaken in 2025.

The Company generated $3.6$4.5 billion of cash from operating activities in 2024,2025, which was $491$925 million or 1626 percent higher than 2023.2024. APA’s higher operating cash flows for 20242025 were primarily driven by higherthe oilcollection of outstanding receivables, lower overall expenses, and gastiming revenuesof resultingother fromworking increasedcapital drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices.items. The Company repurchased 9.212.9 million shares of its common stock for $246$280 million and paid $353$360 million in dividends to APA common stockholders during 2025. The Company ended the year with approximately $4.5 billion of debt, a reduction of approximately $1.6 billion from the end of 2024.

•Daily boe production from the Company’s U.S. assets, which increased 302 percent from 2023,2024, accounted for 62 percent of the Company’s worldwide production during 2024.2025. The Company averaged nineapproximately seven drilling rigs in the U.S. during the year, including fivefour rigs in the Southern Midland Basin and fourthree rigs in the Delaware Basin, and drilled and brought online 159154 operated wells in 2024. The Company’s drilling was primarily focused on oil prospects, and combined with the Callon acquisition, oil production increased approximately 63 percent in the U.S. compared to the prior year.2025. The Company’s core Permian Basin development program continues to representconsistently key growth areas forattract the U.S.largest assets.portion of capital investment.

•During the first quarter of 2024,2025, the Company completedand aits three-wellpartners explorationannounced programpreliminary results of an exploratory well in Alaska, confirming the successful discovery of a workingreservoir. petroleumA systemsuccessful onflow test of the Company’swell acreage.was announced in April, with the well averaging 2,700 b/d during the final flow period. The Company iscontinues currentlyto evaluate the data from the well to determine next steps, and further appraisal drilling anwill additionaldetermine explorationthe wellultimate onsize thisof acreage.the discovery. The Company holds a 50 percent ownership interest in the project.

•During the fourth quarter of 2024, the Company entered into a new gas sales agreement whichwith couldthe resultGovernment inof improvedEgypt. pricingEffective ifJanuary certain2025, substantially all of the Company’s natural gas production thresholdswas aresold met.to EGPC under the terms of this agreement. The newagreement provides the Company with enhanced economic terms that support increased natural gas salesexploration agreementand createsdevelopment activity and the potential foraddition of significant new drilling inventory with expected returns oncomparable parto withthose oil.of the Company’s oil program.

•Callon Petroleum Company Acquisition On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The acquired assets includeincluded approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. The Company believes the acquisition of Callon provides opportunities to reduce costs, improve capital efficiencies, leverage economies of scale, and expand the development inventory that formed the basis of the transaction value.

•Sales of Kinetik Shares During 2022 and 2023, the Company sold a portion of its Kinetik Holdings Inc. (Kinetik) Class A Common Stock (Kinetik Shares) for cash proceeds of $224 million and $228 million, respectively.million. During the first quarter of 2024, the Company sold its remaining shares of Kinetik Class A Common StockShares for cash proceeds of $428 million. On April 3, 2024, the Company’s designated director resigned from the Kinetik Holdings, Inc. (Kinetik) board of directors.

•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 $0.71$1.02 per Mcf in 2024,2025, a 6144 percent decreaseincrease from an average of $1.80$0.71 per Mcf in 2023.2024.

•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 $10.84$12.03 per Mcf in 2024,2025, a 1711 percent decreaseincrease from an average of $13.02$10.84 per Mcf in 2023.2024.

Crude oil revenues for 20242025 totaled $7.0$5.8 billion, a $969$1.2 millionbillion increasedecrease from the 20232024 total of $6.0$7.0 billion. A 20 percent higher average daily production increased 2024 revenues by $1.2 billion compared to 2023, while a 314 percent decrease in average realized prices reduced 2025 revenues by $196$996 million compared to 2024, while a 3 percent lower average daily production decreased revenues by $161 million. Average daily production in 20242025 was 244237 Mb/d, with prices averaging $78.08$66.92 per barrel. Crude oil sales accounted for 8580 percent of the Company’s 20242025 oil and gas production revenues and 5451 percent of its worldwide production.

The Company’s worldwide crude oil production increaseddecreased 416 Mb/d compared to 2023,2024, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were partially offset by natural production decline across all assets, the sale of non-core assets in the U.S.,U.S. and operationalnatural downtimeproduction duedecline, tomostly maintenanceoffset activitiesby drilling activity in the NorthPermian Sea.Basin.

Natural gas revenues for 20242025 totaled $584$770 million, a $296$186 million decreaseincrease from the 20232024 total of $880$584 million. A 3220 percent decreaseincrease in average realized prices reducedincreased 20242025 revenues by $285$118 million compared to 2023,2024, while 210 percent lowerhigher average daily production decreasedincreased revenues by $11$68 million. Average daily production in 20242025 was 814897 MMcf/d, with prices averaging $1.97$2.36 per Mcf. Natural gas sales accounted for 711 percent of the Company’s 20242025 oil and gas production revenues and 3032 percent of its worldwide production.

The Company’s worldwide natural gas production decreasedincreased 1482 MMcf/d compared to 2023,2024, primarily a result of successful drilling activity in Egypt and the Permian Basin. These increases were offset by natural production decline in the North SeaU.S. and U.S.,North reducedSea, gas-focusedthe activitysale of non-core assets in Egypt,the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and theoperational sale of non-core assetsdowntime in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.

NGL revenues for 20242025 totaled $646$650 million, a $138$4 million increase from the 20232024 total of $508$646 million. A 173 percent higher average daily production increased 20242025 revenues by $95$22 million compared to 2023,2024, while ana 83 percent increasedecrease in average realized prices increased 2024decreased revenues by $43$18 million. Average daily production in 20242025 was 7578 Mb/d, with prices averaging $23.37$22.71 per barrel. NGL sales accounted for 89 percent of the Company’s 20242025 oil and gas production revenues and 1617 percent of its worldwide production.

The Company’s worldwide NGL production increased 112 Mb/d compared to 2023,2024, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, partiallyBasin, offset by natural production declinedecline, the sale of non-core assets in the U.S., and curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S.differentials

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. Sales related to purchased volumes increased $647$150 million for the year ended December 31, 20242025 to $1.7 billion from $1.5 billion from $894 million in 2023.2024. Purchased oil and gas sales were partially offset by associated purchase costs of $1.0$1.1 billion and $742$1.0 millionbillion for the years ended December 31, 20242025 and 2023,2024, respectively. The increase in purchased oil and gas sales was primarily driven by increasedhigher oilnatural volumegas salesprices coupledat withvarious activitydelivery associated with the Callon acquisition.locations.

During 2024,2025, LOE increaseddecreased $254$186 million, or 1811 percent, compared to 2023.2024. On a per-boe basis, LOE increaseddecreased $0.48,$1.30, or 513 percent, compared to 2023,2024, from $9.68$10.16 per boe to $10.16$8.86 per boe. The increasedecrease in absolute costs was primarily driven by higherlower workover activity, continued cost reduction efforts in all operating and labor costsareas, and workoverthe activitysale of non-core assets in the Permian Basin. This decrease was partially offset by a full year of operating costs associated with the Callon acquisition. The Company also had higher labor costs and other operating costs trending with general inflation across all regions, which were partially offset by changes in foreign currency exchange rates against the U.S. dollar.transaction.

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:

GPT costs increaseddecreased $98$8 million compared to 2023,2024, primarily the result of increaseddecreased oil and NGL production volumes in the U.S.,U.S. primarilyand associatedlower withaverage thetransportation Callon acquisition, as well as increased charges for transporting gas production.rates.

Purchased oil and gas costs increased $305$23 million for the year ended December 31, 2024,2025, to $1.1 billion from $1.0 billion from $742 million in 2023.2024. The increase is primarily driven by increasedgas oilvolumes volumepurchased purchasesat higher prices during 2025 compared to the prior-year period coupled with activity associated with the Callon acquisition during 2024, partially offset by lower average natural gas prices during 2024 compared to the prior-year period. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $1.5 billion for the year ended 2024, as discussed above.acquisition.

Taxes other than income increaseddecreased $63$41 million compared to 2023,2024, primarily from higherlower severance taxes driven by increasedlower U.S.oil productionprices volumesand primarilylower attributablead tovalorem the Callon acquisition.taxes.

G&A expenses increasedin $212025 decreased $22 million compared to 2023,2024. primarilyFocused drivencost-reduction byefforts higheron overall labor costs across the Companypersonnel and theother Callonoverhead acquisition,expenses partiallydrove a decrease of $67 million, which more than offset by lower cash-basedhigher stock compensation expense resultingof $45 million primarily driven from changesan increase in the Company’s stock price induring 2024.2025. For additional information on the Company’s stock compensation, refer to Note 1312—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

TRS costs increaseddecreased $153$66 million compared to 2023,2024, primarily a result of transaction costs related to the Callon acquisition coupledduring with2024, separationpartially costsoffset inby theemployee North Sea. TRS costs incurred in 2024 primarily comprised $147 million associated with the Callon acquisition, including $76 million of separation costsseparations and $71other millioncost-saving ofreorganization transactioninitiatives andduring integration costs.2025.

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 20242025 increased $735$40 million compared to 2023.2024. The Company’s oil and gas property DD&A rate increasedremained $3.32relatively per boeflat in 20242025 compared to 2023,2024, from $10.12$13.44 per boe to $13.44$13.41 per boe, drivenmainly bythe result of negative gas price-related reserve revisions in the U.S. Permian Basin and impacts resulting from the Callon acquisition in 2024. The increase on an absolute basis was also drivenoffset by highernon-core capitalasset expenditures incurred in the U.S. and the Callon acquisition.divestitures.

Net financing costs during 20242025 increaseddecreased $55$254 million compared to 2023,2024, primarily driven by highergains on extinguishment of debt from the Company’s cash tender purchases in early 2025 and lower overall interest expense from higherlower averageoutstanding long-term debt balances.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. In 2024,2025, the Company accruedrecorded a current tax benefit of $71 million related to the 2024 return-to-accrual adjustment, with an offsetting deferred tax expense of $74the million,same whichamount resultsfor the change in aCAMT tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years.credits.

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. The Company is under audit by the Internal Revenue Service and in various statesstate and foreign jurisdictions as part of its normal course of business.

The Company continues to prudently manage its capital program against a volatile price environment and the effects of global inflation and rising interest rates. Despite these uncertainties, the Company remainsis committedfocused toon its longer-term objectives: (1) to investremain forcommitted long-termto returnsproviding inaffordable, pursuitreliable, ofand moderate,responsibly sustainableproduced production growthenergy; (2) to strengthendeliver 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 (34) to responsiblybuild manageand itsgrow costa structurediverse regardlessand ofbalanced thehigh-quality oilportfolio pricewith environment.scale through acquisitions, exploration, and organic opportunities.

Except as set forth herein, thereThere have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025.2025, as supplemented by Part II, Item 1A—Risk Factors of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026.

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 threefour geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea)., and offshore Suriname. APA also has active development, exploration and appraisal operations ongoing in Suriname, as well as 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.

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, Lebanon, and Gaza,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.

In the firstsecond 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 expectshas anraised additionalits $100 million ofexpected annualized savings target to be$500 achievedmillion by the end of 2026, addingan toincrease theof $350$50 million offrom annualizedits savingsprevious across G&A, LOE, and capital captured during the prior year.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 longer-termcontinued balance sheet strengthening.

•Beginning in the fourth quarter of 2021 and through the end of the firstsecond quarter of 2026, the Company has repurchased 98.2101.0 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 $3.6$3.7 billion of long-term debt, including $555 million repaid subsequent to the end of the first quarter of 2026.debt.

In the firstsecond quarter of 2026, the Company reported net income attributable to common stock of $446$747 million, or $1.26$2.11 per diluted share, compared to net income of $347$603 million, or $0.96$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 quartersix months of 2025. The increase in net income in the second quarter and the first quartersix months of 2026, compared to the second quarter and first quartersix 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 yearprior-year cost savings initiatives.

The Company generated $554$2.3 millionbillion of cash from operating activities during the first threesix months of 2026, 49remaining percentflat lowerwhen thancompared to the first threesix months of 2025. APA’s lower operating cash flows for the first three months of 2026 were primarily driven by the collection of outstanding Egypt receivables in the prior year and timing of other working capital items. The Company paid $88$177 million in dividends to APA common stockholders and repurchased approximately $100 million of Company common stock during the first threesix months of 2026. The Company also repaid $79$752 million of long-term debt that maturedprincipal during the quarter.first six months of 2026.

•Daily boe production from the Company’s U.S. assets, which decreased 119 percent from the firstsecond quarter of 2025, accounted for 6064 percent of the Company’s worldwide production during the firstsecond 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 firstsecond quarter of 2026. The Company brought online 1947 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent a key growth 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 MarchJune 31,30, 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 marketingtrading activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.

•In Egypt, the Company averaged 12 drilling rigs and drilled 1611 new productive wells during the firstsecond quarter of 2026. The Company also averaged 2018 workover rigs as it continues to align itsoptimizing drilling and workover activity with a goal of driving improvedfor capital efficiency. FirstSecond quarter 2026 gross and net production from the Company’s Egypt assets increased 2 percent andwhile 8net percent,production respectively,decreased 13 percent from the firstsecond 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, following the success of the 2025 gas program, 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.

(4) Average sales volumes from the North Sea for the firstsecond quarters of 2026 and 2025 were 28,27514,877 boe/d and 36,70428,015 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.

First-QuarterSecond-Quarter 2026 compared to First-QuarterSecond-Quarter 2025

Crude Oil Crude oil revenues for the firstsecond quarter of 2026 totaled $1.6$1.8 billion, a $44$445 million increase from the comparative 2025 quarter. A 750 percent increase in average realized prices increased first-quartersecond-quarter 2026 oil revenues by $107$688 million compared to the firstsecond quarter of 2025, while 410 percent lower average daily sales volumes decreased revenues by $63$243 million. Crude oil accounted for 8590 percent of total oil and gas production revenues and 52 percent of worldwide production in the firstsecond 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 4.524.0 Mb/d to 232211.3 Mb/d during the firstsecond 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, and the sale of non-core assets in the U.S. Also during the first quarter of 2026, the timing of liftingsdowntime in the North SeaSea. droveSecond anquarter additional2026 4.4net Mb/d decreaseproduction in salesEgypt was negatively impacted by higher price realizations and lower cost recovery volumes compared tounder the samemerged prior-yearconcession period.agreement. These decreases were partially offset by successful drilling activity in the Permian Basin and improved well performance in the North Sea.Basin.

Natural Gas Natural gas revenues for the firstsecond quarter of 2026 totaled $157$41 million, a $76$143 million decrease from the comparative 2025 quarter. A 2574 percent decrease in average realized prices, driven by periods of negative pricing across the Permian Basin, decreased first-quartersecond-quarter 2026 natural gas revenues by $57$135 million compared to the firstsecond quarter of 2025, while 1116 percent lower average daily production decreased gas revenues by $19$8 million. Natural gas accounted for 82 percent of total oil and gas production revenues and 31 percent of worldwide production during the firstsecond quarter of 2026.

The Company’s worldwide natural gas production decreased 99.1142.0 MMcf/d to 824.4752.1 MMcf/d during the firstsecond 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 U.S., and natural production decline in the U.S. and North Sea. These decreases were partially offset by drilling activity in Egypt and the Permian Basin, with Egypt also benefitting from higher realized natural gas prices and improved well performance in the North Sea.

NGL NGL revenues for the firstsecond quarter of 2026 totaled $141$170 million, a $65$17 million decreaseincrease from the comparative 2025 quarter. A 2724 percent decreaseincrease in average realized prices decreasedincreased first-quartersecond-quarter 2026 NGL revenues by $56$36 million compared to the firstsecond quarter of 2025, while 79 percent lower average daily production decreased revenues by $9$19 million. NGLs accounted for 78 percent of total oil and gas production revenues and 17 percent of worldwide production during the firstsecond quarter of 2026.

The Company’s worldwide NGL production decreased 5.67.5 Mb/d to 73.073.3 Mb/d during the firstsecond quarter of 2026 from the comparative prior-year period, primarily a result of increased volume curtailments and weather shut-ins compared with the 2025 period.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 U.S. and natural production decline in the U.S. and North Sea. These decreases were partially offset by drilling activity in the Permian Basin and improved well performance in the North Sea.

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 $385$336 million and $597$460 million during the firstsecond quarters of 2026 and 2025, respectively. Purchased oilrespectively, and gas sales were partially offset by associated purchase costs of $75$721 million and $474$1.1 millionbillion during the first quarterssix 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 compared toand costs realized during the second quarter and the first quartersix months of 2026 was primarily attributable to extreme Permian Basin natural gas priceprices, differentialswhich included periods of negative pricing, compared with Houston Ship Channel pricing.

LOE decreased $45$14 million and $59 million from the firstsecond quarter and the first six months of 2025.2025, respectively. On a per-unit basis, LOE decreasedincreased 510 percent and 2 percent in the firstsecond quarter and the first six months of 20262026, respectively, when compared to the second quarter and the first quartersix months of 2025. The decrease in overall absolute costs was primarily driven by the sale of non-core assets in the Permian BasinBasin, timing of liftings in the North Sea, and continued cost reduction efforts across all operating areas.

GPT costs decreased $13$17 million and $30 million from the second quarter and the first quartersix 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 $399$426 million and $825 million from the second quarter and the first quartersix 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 20252025. andPeriods of negative gas volumespricing purchasedduring at significantly lower prices2026 in the Permian Basin.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.

Exploration expenses decreasedincreased $4$15 million and $11 million from the second quarter and the first quartersix months of 2025, respectively, primarily the result of lowerhigher explorationdry overhead and geological and geophysicalhole expense in the first quarter of 2026Egypt compared to the same prior-year period.periods.

G&A expenses increased $17$2 million and $19 million from the second quarter and the first quartersix months of 2025, respectively, primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price during the period,periods, partially offset by impacts from cost-reduction efforts on personnel and other overhead expenses.

TRS costs increased $1 million and decreased $30$29 million from the second quarter and the first six months of 2025, respectively. TRS costs in the second quarter of 2025,2026 were primarily associatedrelated withto 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 quartersix months of 2025.

Total DD&A expenses decreased $90$26 million and $116 million from the firstsecond quarter and the first six months of 2025.2025, respectively. The Company’s DD&A rate on its oil and gas properties increased $1.11 and decreased $1.21$0.05 per boe from the firstsecond quarter and the first six months of 2025.2025, 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 drivendue byto lower DD&A rates driven by lower production volumes resulting from the sale of non-core assets in the Permian Basin during 2025.Basin.

Net financing costs decreased $8 million and increased $114$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 2025,2026 primarilywas 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 quartersix months of 2025, partially offset by a decrease in interest expense from the associated lower long-term debt balance.

The Company’s effective income tax rate for the threesix months ended MarchJune 31,30, 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 threesix months ended MarchJune 31,30, 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.

The Company plansexpects to invest approximately $2.1 billion in upstream capital investment in 2026. The Company is committed to maintaining a safe, steady,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.

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primaryprincipal 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 threesix months of 2026 totaled $554$2.3 million,billion, $542$17 million lower fromthan the first threesix months of 2025,2025. primarily2026 due to lower revenuesbenefited from decreasedhigher oil and gas production,revenues lowerfrom naturalhigher realized oil prices and higher margins on third-party purchased oil and gas prices,sales. 2025 benefitted from the collection of outstanding Egypt receivables in 2025, and timing of other working capital items.

Additions to Oil & Gas Property During the first threesix months of 2026 and 2025, exploration and development cash expenditures were $542$1.1 millionbillion and $777$1.4 million,billion, respectively. The decrease in capital investment compared to the prior-year period is directlylargely relateddriven toby 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 threesix months of 2026, compared to an average of approximately 2221 drilling rigs during the first threesix months of 2025.

Leasehold and Property Acquisitions During the first threesix months of 2026 and 2025, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4$6 million and $13$20 million, respectively.

Payments on Fixed-Rate Debt During the first threesix months of 2026, the Company repaid in cash on maturity $79$754 million of long-term debtdebt, duewhich duringcomprised theoutstanding quarter,principal amounts and make-whole premiums, plus accrued and unpaid interest to the maturity date.interest.

During the first threesix 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 $905$954 million, reflecting principal amounts, discount to par, and associated fees.

Dividends Paid to APA Common Stockholders During the first threesix months of 2026 and 2025, the Company paid $88$177 million and $91$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 threesix months of 2026 and 2025, the Company paid $65$164 million and $126$217 million, respectively, in cash distributions to Sinopec.

Cash and Cash Equivalents As of MarchJune 31,30, 2026, the Company had $293$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 MarchJune 31,30, 2026, the Company had $4.4$3.7 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache and finance lease obligations. As of MarchJune 31,30, 2026, current debt included $2 million of finance lease obligations and $132 million of APA and Apache notes coming due within the next year.obligations.

Indenture Debt Activity On MarchJune 15,29, 2026, APA andfully Apacheredeemed repaidits inprivately cashplaced on maturity the outstanding $79 million aggregate principal amount of their respective 7.70%4.250% Notes due 2026,2030, 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 maturityredemption date.