# APA Corp (APA) Informational only - not investment advice. CIK: 0001841666 SIC: 1311 Crude Petroleum & Natural Gas SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1311 Crude Petroleum & Natural Gas](/industry/1311/) Latest 10-K filed: 2026-02-26 SEC page: https://www.sec.gov/edgar/browse/?CIK=1841666 Filing source: https://www.sec.gov/Archives/edgar/data/1841666/000184166626000015/apa-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Net income | 1434000000 | USD | 2025 | 2026-02-26 | | Assets | 17761000000 | USD | 2025 | 2026-02-26 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001841666.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net income | | | | | 2,855,000,000 | 804,000,000 | 1,434,000,000 | | Operating income | -2,152,000,000 | -4,102,000,000 | 2,860,000,000 | 5,565,000,000 | 3,696,000,000 | 2,444,000,000 | 3,087,000,000 | | Diluted EPS | -9.43 | -12.86 | 2.59 | 11.02 | 9.25 | 2.27 | 3.99 | | Assets | 18,107,000,000 | 12,746,000,000 | 13,303,000,000 | 13,147,000,000 | 15,244,000,000 | 19,390,000,000 | 17,761,000,000 | | Stockholders' equity | | -1,639,000,000 | -1,595,000,000 | 423,000,000 | 2,655,000,000 | 5,280,000,000 | 6,093,000,000 | | Cash and cash equivalents | | 262,000,000 | 302,000,000 | 245,000,000 | 87,000,000 | 625,000,000 | 516,000,000 | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance ## Latest 10-K MD&A Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of APA Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (filed with the SEC on February 28, 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 operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). 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. 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 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+. 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 price volatility and effectively manage its investment programs. With increasing uncertainty around commodity prices during the first quarter of 2025, the Company announced a significant cost reduction initiative to drive sustainable cost savings for the long-term. This included reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices. The Company achieved $350 million in annualized savings across G&A, LOE, and capital as of year-end 2025. The Company expects $450 million of annualized savings by the end of 2026. Additionally, 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 through dividends and share repurchases creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening. •The Company paid a quarterly dividend of $0.25 per share on its common stock during 2025. •Beginning in the fourth quarter of 2021 and through the end of 2025, the Company has repurchased 98.2 million shares of the Company’s common stock. As of December 31, 2025, the Company had remaining authorization to repurchase up to 21.9 million shares under the Company’s share repurchase program. 34 Financial and Operational Highlights During 2025, the Company reported net income attributable to common stock of $1.4 billion, or $3.99 per diluted share, compared to net income of $804 million, or $2.27 per diluted share, in 2024. The increase in net income during 2025 was primarily the result of by $1.1 billion of impairments recorded in 2024, which included oil and gas property impairments of $796 million in the North Sea and $315 million in the U.S. The Company also recorded lower operating expenses in 2025 compared to the prior-year period, the result of focused cost-reduction efforts undertaken in 2025. The Company generated $4.5 billion of cash from operating activities in 2025, which was $925 million or 26 percent higher than 2024. APA’s higher operating cash flows for 2025 were primarily driven by the collection of outstanding receivables, lower overall expenses, and timing of other working capital items. The Company repurchased 12.9 million shares of its common stock for $280 million and paid $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. Key operational highlights for the year include: United States •Daily boe production from the Company’s U.S. assets, which increased 2 percent from 2024, accounted for 62 percent of the Company’s worldwide production during 2025. The Company averaged approximately seven drilling rigs in the U.S. during the year, including four rigs in the Midland Basin and three rigs in the Delaware Basin, and drilled and brought online 154 operated wells in 2025. The Company’s core Permian Basin development program continues to consistently attract the largest portion of capital investment. •In the Permian Basin, the Company is currently operating five rigs, reflecting improved capital efficiency while sustaining the pace of wells brought online. The Company anticipates continuing this level of activity to deliver 2026 oil production consistent with the prior year. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending. •The Company holds approximately 750,000 MMBtu/d of firm capacity on various pipelines. As of December 31, 2025, 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 marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements. •During the first quarter of 2025, the Company and its partners announced preliminary results of an exploratory well in Alaska, confirming the successful discovery of a reservoir. A successful flow test of the well was announced in April, with the well averaging 2,700 b/d during the final flow period. The Company continues to evaluate the data from the well to determine next steps, and further appraisal drilling will determine the ultimate size of the discovery. The Company holds a 50 percent ownership interest in the project. International •During the fourth quarter of 2024, the Company entered into a new gas sales agreement with the Government of Egypt. Effective January 2025, substantially all of the Company’s natural gas production was sold to EGPC under the terms of this agreement. The agreement provides the Company with enhanced economic terms that support increased natural gas exploration and development activity and the potential addition of significant new drilling inventory with expected returns comparable to those of the Company’s oil program. •In Egypt, the Company averaged 12 drilling rigs and drilled 71 new productive wells during 2025. During the same period, the Company averaged 19 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. The 2025 gross and net production from the Company’s Egypt assets decreased 2 percent and 6 percent, respectively, from 2024. •During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The Government also helped facilitate significant payments in the third quarter of 2025, nearly eliminating past due receivables. For a more detailed discussion related to the Company’s various geographic segments, refer to “Exploration and Production—Operating Areas” set forth in Part I, Items 1 and 2 of this Annual Report on Form 10-K. 35 Acquisition and Divestiture Activity Over the Company’s history, it has repeatedly demonstrated the ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize APA’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of acquisitions and divestitures designed to enhance the Company’s portfolio and monetize nonstrategic assets in order to allocate resources to more impactful exploration and development opportunities. These acquisitions and divestitures include: •Sale of Non-core Permian Basin Properties During the second quarter of 2025, the Company completed the sale of all of its New Mexico Permian assets. The assets had a carrying value of $282 million and associated retirement obligation of $9 million, which were exchanged for total cash consideration of $571 million, inclusive of post-closing adjustments. •Egypt Acreage Acquisition During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. •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 included approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. •Sale of Non-core Permian Basin Properties On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $1.1 billion and associated asset retirement obligation of $224 million for total cash proceeds of $869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf. •Non-core Acreage Divestiture During 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $255 million and the assumption of asset retirement obligations of $42 million. •Mineral Rights Divestiture During 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $394 million subject to post-closing adjustments. •Sales of Kinetik Shares During 2023, the Company sold a portion of its Kinetik Holdings Inc. (Kinetik) Class A Common Stock (Kinetik Shares) for cash proceeds of $228 million. During the first quarter of 2024, the Company sold its remaining Kinetik Shares for cash proceeds of $428 million. On April 3, 2024, the Company’s designated director resigned from the Kinetik board of directors. For detailed information regarding APA’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 36 Results of Operations Oil, Natural Gas, and Natural Gas Liquids Production Revenues The Company’s production revenues and respective contribution to total revenues by country are as follows: For the Year Ended December 31, 2025 2024 2023 $ Value % Contribution $ Value % Contribution $ Value % Contribution ($ in millions) Oil Revenues: United States $ 3,010  52  % $ 3,572  51  % $ 2,241  37  % Egypt(1) 2,177  37  % 2,620  38  % 2,683  45  % North Sea 622  11  % 774  11  % 1,073  18  % Total(1) $ 5,809  100  % $ 6,966  100  % $ 5,997  100  % Natural Gas Revenues: United States $ 193  25  % $ 126  22  % $ 297  34  % Egypt(1) 460  60  % 313  53  % 346  39  % North Sea 117  15  % 145  25  % 237  27  % Total(1) $ 770  100  % $ 584  100  % $ 880  100  % NGL Revenues: United States $ 616  95  % $ 617  96  % $ 480  94  % North Sea 34  5  % 29  4  % 28  6  % Total(1) $ 650  100  % $ 646  100  % $ 508  100  % Oil and Gas Revenues: United States $ 3,819  53  % $ 4,315  53  % $ 3,018  41  % Egypt(1) 2,637  36  % 2,933  36  % 3,029  41  % North Sea 773  11  % 948  11  % 1,338  18  % Total(1) $ 7,229  100  % $ 8,196  100  % $ 7,385  100  % (1)Includes revenues attributable to a noncontrolling interest in Egypt. 37 Production The following table presents production volumes by country: For the Year Ended December 31, 2025 Increase (Decrease) 2024 Increase (Decrease) 2023 Oil Volumes – b/d: United States(5) 125,526  (2)% 128,531  63% 78,889  Egypt(3)(4) 87,719  (1)% 89,027  —% 89,129  North Sea 24,186  (8)% 26,340  (24)% 34,728  Total 237,431  (3)% 243,898  20% 202,746  Natural Gas Volumes – Mcf/d: United States(5) 514,502  6% 483,446  7% 452,281  Egypt(3)(4) 350,774  21% 291,011  (11)% 325,778  North Sea 31,318  (22)% 39,986  (20)% 50,284  Total 896,594  10% 814,443  (2)% 828,343  NGL Volumes – b/d: United States(5) 76,264  3% 73,877  17% 62,997  North Sea 1,256  5% 1,201  (3)% 1,240  Total 77,520  3% 75,078  17% 64,237  BOE per day:(1) United States(5) 287,539  2% 282,983  30% 217,266  Egypt(3)(4) 146,182  6% 137,529  (4)% 143,425  North Sea(2) 30,662  (10)% 34,204  (23)% 44,349  Total 464,383  2% 454,716  12% 405,040  (1)The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products. (2)Average sales volumes from the North Sea were 31,168 boe/d, 33,954 boe/d, and 45,476 boe/d for 2025, 2024, and 2023, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings. (3)Gross oil, natural gas, and NGL production in Egypt were as follows: 2025 2024 2023 Oil (b/d) 125,511  137,150  141,985  Natural Gas (Mcf/d) 486,462  443,551  500,080  (4)Includes net production volumes per day attributable to a noncontrolling interest in Egypt of: 2025 2024 2023 Oil (b/d) 29,267  29,698  29,739  Natural Gas (Mcf/d) 117,035  97,078  108,703  (5)Production volumes per day in the Company’s Wildfire field were as follows: 2025 2024 2023 Oil (b/d) 29,023  19,970  15,644  Natural Gas (Mcf/d) 52,650  41,136  29,537  NGL (b/d) 10,127  7,540  5,622  38 Pricing The following table presents pricing information by country: For the Year Ended December 31, 2025 Increase (Decrease) 2024 Increase (Decrease) 2023 Average Oil Price - Per barrel: United States $ 65.71  (13)% $ 75.92  (2)% $ 77.84  Egypt 67.97  (15)% 80.41  (2)% 82.47  North Sea 69.31  (14)% 80.74  (2)% 82.75  Total 66.92  (14)% 78.08  (3)% 80.72  Average Natural Gas Price - Per Mcf: United States $ 1.02  44% $ 0.71  (61)% $ 1.80  Egypt 3.59  22% 2.94  1% 2.91  North Sea 12.03  11% 10.84  (17)% 13.02  Total 2.36  20% 1.97  (32)% 2.91  Average NGL Price - Per barrel: United States $ 22.13  (3)% $ 22.83  9% $ 20.85  North Sea 43.59  (8)% 47.59  —% 47.77  Total 22.71  (3)% 23.37  8% 21.54  Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2025 were down 14 percent compared to 2024, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2025 averaged $66.92 per barrel. Continued volatility in the commodity price environment reinforces the importance of the Company’s asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Prices for all types and grades of crude oil generally move in the same direction. Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows: •The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $1.02 per Mcf in 2025, a 44 percent increase from an average of $0.71 per Mcf in 2024. •In Egypt, substantially all of the Company’s 2025 natural gas production is sold to EGPC pursuant to a gas sales agreement that establishes pricing based on a minimum realized price of $2.65 per MMBtu, with the potential for higher pricing on incremental volumes when pre-determined production thresholds are met. The gas sales agreement was effective beginning January 2025. In the periods prior to the current agreement, the natural gas production in Egypt was primarily sold to EGPC at an industry-pricing formula of $2.65 per MMBtu. Overall, the Company’s Egypt operations averaged $3.59 per Mcf in 2025, a 22 percent increase from an average of $2.94 per Mcf in 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 $12.03 per Mcf in 2025, a 11 percent increase from an average of $10.84 per Mcf in 2024. 39 NGL Prices The Company’s U.S. NGL production, which accounted for 98 percent of the Company’s total 2025 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser. Crude Oil Revenues Crude oil revenues for 2025 totaled $5.8 billion, a $1.2 billion decrease from the 2024 total of $7.0 billion. A 14 percent decrease in average realized prices reduced 2025 revenues by $996 million compared to 2024, while a 3 percent lower average daily production decreased revenues by $161 million. Average daily production in 2025 was 237 Mb/d, with prices averaging $66.92 per barrel. Crude oil sales accounted for 80 percent of the Company’s 2025 oil and gas production revenues and 51 percent of its worldwide production. The Company’s worldwide crude oil production decreased 6 Mb/d compared to 2024, primarily a result of the sale of non-core assets in the U.S. and natural production decline, mostly offset by drilling activity in the Permian Basin. Natural Gas Revenues Natural gas revenues for 2025 totaled $770 million, a $186 million increase from the 2024 total of $584 million. A 20 percent increase in average realized prices increased 2025 revenues by $118 million compared to 2024, while 10 percent higher average daily production increased revenues by $68 million. Average daily production in 2025 was 897 MMcf/d, with prices averaging $2.36 per Mcf. Natural gas sales accounted for 11 percent of the Company’s 2025 oil and gas production revenues and 32 percent of its worldwide production. The Company’s worldwide natural gas production increased 82 MMcf/d compared to 2024, primarily a result of successful drilling activity in Egypt and the Permian Basin. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets in the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and operational downtime in the U.S. NGL Revenues NGL revenues for 2025 totaled $650 million, a $4 million increase from the 2024 total of $646 million. A 3 percent higher average daily production increased 2025 revenues by $22 million compared to 2024, while a 3 percent decrease in average realized prices decreased revenues by $18 million. Average daily production in 2025 was 78 Mb/d, with prices averaging $22.71 per barrel. NGL sales accounted for 9 percent of the Company’s 2025 oil and gas production revenues and 17 percent of its worldwide production. The Company’s worldwide NGL production increased 2 Mb/d compared to 2024, primarily a result of increased drilling activity in the Permian Basin, offset by natural production decline, the sale of non-core assets in the U.S., and curtailment of volumes at Alpine High in response to extreme Waha basis differentials Purchased Oil and Gas Sales Purchased oil and gas sales represent volumes primarily attributable to domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations and delivery commitments. Sales related to purchased volumes increased $150 million for the year ended December 31, 2025 to $1.7 billion from $1.5 billion in 2024. Purchased oil and gas sales were partially offset by associated purchase costs of $1.1 billion and $1.0 billion for the years ended December 31, 2025 and 2024, respectively. The increase in purchased oil and gas sales was primarily driven by higher natural gas prices at various delivery locations. 40 Operating Expenses The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2025, 2024, and 2023. All operating expenses include costs attributable to a noncontrolling interest in Egypt. For the Year Ended December 31, 2025 2024 2023 (In millions) Lease operating expenses $ 1,504  $ 1,690  $ 1,436  Gathering, processing, and transmission 424  432  334  Purchased oil and gas costs 1,070  1,047  742  Taxes other than income 229  270  207  Exploration 131  313  195  General and administrative 350  372  351  Transaction, reorganization, and separation 102  168  15  Depreciation, depletion, and amortization: Oil and gas property and equipment 2,275  2,235  1,500  Gathering, processing, and transmission assets 6  6  6  Other assets 23  25  34  Asset retirement obligation accretion 158  148  116  Impairments 44  1,129  61  Financing costs, net 113  367  312  Lease Operating Expenses (LOE) LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 51 percent of the Company’s total 2025 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties. During 2025, LOE decreased $186 million, or 11 percent, compared to 2024. On a per-boe basis, LOE decreased $1.30, or 13 percent, compared to 2024, from $10.16 per boe to $8.86 per boe. The decrease in absolute costs was primarily driven by lower workover activity, continued cost reduction efforts in all operating areas, and the sale of non-core assets in the Permian Basin. This decrease was partially offset by a full year of operating costs associated with the Callon transaction. Gathering, Processing, and Transmission (GPT) GPT expenses include amounts paid to third-party carriers for gathering and transmission services for the Company’s upstream natural gas production. The following table presents a summary of these expenses: For the Year Ended December 31, 2025 2024 2023 (In millions) Third-party processing and transmission costs $ 424  $ 409  $ 225  Midstream service costs – Kinetik —  23  109  Upstream processing and transmission costs 424  432  334  Total Gathering, processing, and transmission $ 424  $ 432  $ 334  GPT costs decreased $8 million compared to 2024, primarily the result of decreased oil production volumes in the U.S. and lower average transportation rates. 41 Purchased Oil and Gas Costs Purchased oil and gas costs increased $23 million for the year ended December 31, 2025, to $1.1 billion from $1.0 billion in 2024. The increase is primarily driven by gas volumes purchased at higher prices during 2025 compared to the prior-year period coupled with activity associated with the Callon acquisition. Taxes Other Than Income Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes. Taxes other than income decreased $41 million compared to 2024, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes. Exploration Expenses Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses: For the Year Ended December 31, 2025 2024 2023 (In millions) Unproved leasehold impairments $ 2  $ 35  $ 22  Dry hole expenses 67  201  92  Geological and geophysical expenses 8  21  19  Exploration overhead and other 54  56  62  Total Exploration $ 131  $ 313  $ 195  Exploration expenses decreased $182 million compared to 2024, primarily the result of higher dry hole expenses in Suriname and Alaska and unproved leasehold impairments during 2024. Dry hole expenses in 2025 primarily relate to increased exploration drilling in Egypt. General and Administrative (G&A) Expenses G&A expenses in 2025 decreased $22 million compared to 2024. Focused cost-reduction efforts on personnel and other overhead expenses drove a decrease of $67 million, which more than offset higher stock compensation expense of $45 million primarily driven from an increase in the Company’s stock price during 2025. For additional information on the Company’s stock compensation, refer to Note 12—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Transaction, Reorganization, and Separation (TRS) Costs TRS costs decreased $66 million compared to 2024, primarily a result of transaction costs related to the Callon acquisition during 2024, partially offset by employee separations and other cost-saving reorganization initiatives during 2025. 42 Depreciation, Depletion and Amortization (DD&A) DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2025 increased $40 million compared to 2024. The Company’s oil and gas property DD&A rate remained relatively flat in 2025 compared to 2024, from $13.44 per boe to $13.41 per boe, mainly the result of negative gas price-related reserve revisions in the U.S. Permian Basin offset by non-core asset divestitures. Impairments During 2025, the Company recorded $44 million of impairments, which included $18 million of non-operated proved oil and gas property in Egypt, approximately $18 million related to the sale of an office building in the U.S., a $1 million impairment for GPT facilities in Egypt, and $7 million of inventory impairments in the North Sea. During 2024, the Company recorded $1.1 billion of impairments, which included $796 million of oil and gas property impairments in the North Sea, a $315 million impairment of certain oil and gas properties in the U.S. held-for-sale, and $18 million of inventory impairments in the North Sea and U.S. Financing Costs, Net Financing costs incurred during 2025, 2024, and 2023 comprised the following: For the Year Ended December 31, 2025 2024 2023 (In millions) Interest expense $ 323  $ 402  $ 351  Amortization of debt issuance costs 7  6  4  Capitalized interest (45) (29) (24) Gain on extinguishment of debt (147) —  (9) Interest income (25) (12) (10) Total Financing costs, net $ 113  $ 367  $ 312  Net financing costs during 2025 decreased $254 million compared to 2024, primarily driven by gains on extinguishment of debt from the Company’s cash tender purchases in early 2025 and lower overall interest expense from lower outstanding long-term debt balances. Provision for Income Taxes For the year ended December 31, 2025, income tax expense increased by $682 million to $1.1 billion from $417 million in 2024. The Company’s 2025 and 2024 effective income tax rates were primarily impacted by taxes related to foreign operations. On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy), increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included further amendments to the Energy Profits Levy, 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. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded tax expense of $78 million and $174 million related to the change in tax law in 2025 and 2023, respectively. 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 2025, the Company recorded a current tax benefit of $71 million related to the 2024 return-to-accrual adjustment, with an offsetting deferred tax expense of the same amount for the change in CAMT credits. 43 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 CAMT purposes with regular tax treatment starting in 2026. OBBBA did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the law change resulted in a current tax benefit of $42 million fully offset by a deferred tax expense of the same amount. On September 30, 2025, the Internal Revenue Service issued further interim guidance on CAMT. Among other changes, the guidance provided for a reduction to CAMT related to net operating loss utilization for regular federal income tax purposes. This guidance did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the guidance resulted in a current tax benefit of $72 million, fully offset by a deferred tax expense of the same amount. In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, the Company does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements. Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be “more likely than not.” The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. For additional information regarding income taxes, refer to Note 9—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 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 state and foreign jurisdictions as part of its normal course of business. 44 Capital and Operational Outlook 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 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 2026, the Company plans to invest approximately $2.1 billion in upstream capital investment. The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its planned capital investment program. For 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. In the Permian Basin, the Company is currently operating five rigs, reflecting improved capital efficiency. The Company anticipates continuing this level of activity to deliver consistent year-over-year oil production. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending. The Company is planning a 12-rig program in Egypt, with five to six rigs dedicated to gas exploration. This activity set translates to a combined development capital budget for the Permian Basin and Egypt of approximately $1.8 billion. In addition, the Company will invest approximately $70 million for exploration in Alaska and Suriname and $230 million for Suriname development. This investment profile underscores the progress the Company has made on capital efficiency over the course of 2025. At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s current commitment to return capital to shareholders through a mix of dividends and share buybacks remains unchanged. Capital Resources and Liquidity Operating cash flows are the Company’s primary 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. 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 sustained decreases in 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. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2025, 2024, and 2023, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 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. 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 Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K. 45 Sources and Uses of Cash The following table presents the sources and uses of the Company’s cash and cash equivalents for the years presented: For the Year Ended December 31,     2025 2024 2023 (In millions) Sources of Cash and Cash Equivalents: Net cash provided by operating activities $ 4,545  $ 3,620  $ 3,129  Fixed-rate debt borrowings 846  —  —  Proceeds from asset divestitures 611  1,609  29  Proceeds from term loan facility —  1,500  —  Proceeds from sale of Kinetik shares —  428  228  Total Sources of Cash and Cash Equivalents 6,002  7,157  3,386  Uses of Cash and Cash Equivalents: Additions to oil and gas property(1) 2,740  2,851  2,313  Acquisition of Delaware Basin properties —  —  24  Leasehold and property acquisitions 26  60  20  Payments on term loan facility 900  600  —  Payments on commercial paper and revolving credit facilities, net 333  40  194  Payments on Callon Credit Agreement —  472  —  Payments on fixed-rate debt 1,016  1,641  65  Dividends paid to APA common stockholders 360  353  308  Distributions to noncontrolling interest 430  268  238  Treasury stock activity, net 280  246  329  Other, net 26  88  53  Total Uses of Cash and Cash Equivalents 6,111  6,619  3,544  Increase (decrease) in cash and cash equivalents $ (109) $ 538  $ (158) (1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Annual Report on Form 10-K, which include accruals. Sources of Cash and Cash Equivalents Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense. Net cash provided by operating activities for the year ended December 31, 2025 totaled $4.5 billion, up $925 million from the year ended December 31, 2024, primarily due to collection of outstanding receivables, lower overall expenses, 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 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Fixed-Rate Debt Borrowings During the year ended December 31, 2025, the Company issued new notes for proceeds of $846 million, after deducting discounts and loan costs, to fund in part APA’s purchase of Apache notes in APA’s cash tender offers. Proceeds from Asset Divestitures The Company received $611 million and $1.6 billion in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2025 and 2024, respectively. For more information regarding the Company’s divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 46 Uses of Cash and Cash Equivalents Additions to Oil & Gas Property Exploration and development cash expenditures were $2.7 billion and $2.9 billion for the years ended December 31, 2025 and 2024, respectively. The decrease in capital investment is reflective of the Company’s plan to streamline capital deployment and the sale of certain non-core assets and leasehold in the Permian Basin. The Company operated an average of 19 drilling rigs during 2025, compared to an average of 22 drilling rigs during 2024. Leasehold and Property Acquisitions During 2025 and 2024, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $26 million and $60 million, respectively. Payments on Term Loan Facility During 2025 and 2024, the Company made payments of $900 million and $600 million, respectively, on its syndicated term loan credit agreement and fully repaid the term loans. For additional details of this credit agreement, see “Unsecured Committed Term Loan Facility” in the Liquidity section below. Payments on Commercial Paper and Revolving Credit Facilities, Net During 2025, the Company made net payments of $333 million on its commercial paper and U.S. dollar denominated syndicated credit facility borrowings. As of December 31, 2025, there were no outstanding borrowings under the Company’s commercial paper or syndicated credit facilities. Payments on Fixed-Rate Debt During 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures of Apache and made open market repurchases of indenture debt of APA and Apache, and Apache redeemed certain notes for aggregate cash payments of $1.0 billion, reflecting principal amounts, discount to par, and associated fees. During 2024, the Company financed Callon’s repayment pursuant to Callon’s cash tender offers for, and redemptions of all senior notes issued under Callon’s indentures for an aggregate cash payment of $1.6 billion, reflecting principal amounts, premium to par, and associated fees. Dividends Paid to APA Common Stockholders The Company paid $360 million and $353 million during the years ended December 31, 2025 and 2024, respectively, for dividends on its common stock. Distributions to Noncontrolling Interest Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $430 million and $268 million during the years ended December 31, 2025 and 2024, respectively, in cash distributions to Sinopec. Treasury Stock Activity, Net During 2025, the Company repurchased 12.9 million shares at an average price of $21.73 per share totaling $280 million, and as of December 31, 2025, the Company had remaining authorization to repurchase 21.9 million shares. During 2024, the Company repurchased 9.2 million shares at an average price of $26.83 per share totaling $246 million. Liquidity The following table presents a summary of the Company’s key financial indicators as of December 31: 2025 2024 (In millions) Cash and cash equivalents $ 516  $ 625  Total debt – APA and Apache 4,493  6,044  Total equity 7,003  6,362  Available committed borrowing capacity under syndicated credit facilities 4,020  2,966  Cash and Cash Equivalents As of December 31, 2025, the Company had $516 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 December 31, 2025, the Company had $4.5 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache, and finance lease obligations. As of December 31, 2025, current debt included $2 million of finance lease obligations and $211 million of APA and Apache notes coming due within the next year. 47 Indenture Debt Activity On August 20, 2025, Apache redeemed the outstanding $51 million principal amount of 4.625% Notes due 2025, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. During 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 $122 million for an aggregate purchase price of $112 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $13 million. The Company recognized a $12 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025. The indentures under which APA has issued senior notes and debentures restrict it from issuing or guaranteeing certain secured indebtedness, consolidating with or merging into another person, and transferring or leasing its properties and assets as an entirety or substantially as an entirety to any person. Indentures of APA and Apache do not contain prepayment obligations in the event of a decline in credit ratings. In connection with the transactions summarized below under “APA Exchange and Tender Offers for Apache Indenture Debt,” Apache’s indentures were amended on January 10, 2025, to remove certain restrictive and reporting covenants, except those applicable to certain notes maturing in 2026 and 2027. APA Exchange and Tender Offers for Apache Indenture Debt On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA’s cash tender offers. In settling these offerings pursuant to their respective terms: •APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA’s exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA’s 6.10% Notes due 2035 and $500 million aggregate principal amount of APA’s 6.75% Notes due 2055. •In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration. •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. •Net proceeds from the sale of the notes in APA’s new notes offering, after deducting the initial purchasers’ discounts and estimated offering expenses, were approximately $839 million and used to fund in part APA’s purchase of Apache notes in APA’s cash tender offers. •Each series of APA notes and debentures issued in settlement of the exchange and tender offers had the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged. •Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering were fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than $1 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025. •APA entered into two registration rights agreements pursuant to which APA agreed to register under the Securities Act of 1933, as amended, the notes and debentures that APA issued in the exchange and tender offers and new notes offering (collectively, the Unregistered Notes). On September 18, 2025, APA settled registered exchange offers for the Unregistered Notes, issuing registered notes and debentures in the same aggregate principal amount as the Unregistered Notes accepted for exchange and canceled and otherwise on terms substantially identical in all material respects to the applicable series of Unregistered Notes. Of the $3.6 billion aggregate principal amount of Unregistered Notes covered by the registered exchange offers, 99 percent was exchanged for registered notes and debentures, and the remaining Unregistered Notes remained outstanding. 48 Unsecured 2025 Committed Bank 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 2025 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 2025 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. Apache guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025. The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022, one of which was denominated in US dollars with aggregate commitments of US$1.8 billion (the 2022 USD Agreement) and second of which was denominated in pounds sterling with aggregate commitments of £1.5 billion (the 2022 GBP Agreement). On January 15, 2025, the Company terminated commitments under both the 2022 USD Agreement and 2022 GBP Agreement in connection with entry into the 2025 Agreements. As of December 31, 2025, there were no borrowings or letters of credit outstanding under the 2025 USD Agreement and no borrowings and an aggregate £1.0 million in letters of credit outstanding under the 2025 GBP Agreement. As of December 31, 2024, there were $10 million of borrowings and no letters of credit outstanding under the 2022 USD Agreement, and no borrowings and an aggregate £303 million in letters of credit outstanding under the 2022 GBP Agreement. All borrowings under the 2025 USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin varying from 0.0% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.00% to 1.675% (Applicable Margin). All borrowings under the 2025 GBP Agreement bear interest with respect to any business day at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average with respect to such business day published by the Bank of England, plus the Applicable Margin. Each 2025 Agreement also requires the borrower to pay quarterly (i) a facility fee on total commitments at a per annum rate that varies from 0.125% to 0.325% and (ii) a commission on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA (Long-Term Debt Rating). The current Base Rate Margin is 0.30%, the Applicable Margin is 1.30%, and the facility fee is 0.20%. Borrowers under each 2025 Agreement, which include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default, such as: •A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65% at the end of any fiscal quarter. •A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada; liens on assets also are permitted if debt secured thereby does not exceed 15% of APA’s consolidated net tangible assets. 49 •Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold. •Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries. The 2025 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings. The Company was in compliance with the terms of the 2025 Agreements as of December 31, 2025. 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 December 31, 2025 and 2024, there were no outstanding borrowings under these facilities. As of December 31, 2025, there were £901 million and $10 million in letters of credit outstanding under these facilities. As of December 31, 2024, there were £640 million and $11 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 program was established in December 2023, and the maximum aggregate face amount of CP Notes issuable thereunder was increased to $2.0 billion from $1.8 billion on June 20, 2025. The maturities of the 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 December 31, 2025, included the $2.0 billion 2025 USD Agreement. Payment of the CP Notes was unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on June 20, 2025. 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 December 31, 2025, the Company had no CP Notes outstanding. As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which was classified as long-term debt. Unsecured Committed Term Loan Facility On January 30, 2024, APA entered into a syndicated credit agreement providing for committed senior unsecured delayed-draw term loans to APA, the proceeds of which could be used to refinance certain indebtedness of Callon. On April 1, 2024, APA acquired Callon and borrowed $1.5 billion under this credit agreement maturing April 1, 2027, of which $900 million remained outstanding as of December 31, 2024. APA fully prepaid this credit agreement on March 10, 2025. The repayment was partially financed with borrowings under APA’s 2025 USD Agreement and commercial paper program. 50 Contractual Obligations Purchase Obligations From time to time, the Company enters into agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments and agreements to secure capacity rights on third-party pipelines. As of December 31, 2025, the Company had contractual obligations totaling $971 million, of which $778 million is related to U.S. firm transportation contracts, $133 million is related to U.S. purchase obligations, $28 million is related to the merged concession agreement with the EGPC, and $32 million is related to other items. Leases In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 842 (Leases). As of December 31, 2025, the Company had net undiscounted minimum commitments of $428 million and $34 million for operating and finance leases, respectively. Interest Expense Future interest payments based on the current maturity dates of the Company’s fixed-rate notes and debentures as of December 31, 2025 are approximately $3.7 billion. For additional information regarding these obligations, refer to Note 8—Debt and Financing Costs and Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. For information regarding the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties, refer to Note 7—Asset Retirement Obligation in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. For information regarding pension or postretirement benefit obligations, refer to Note 11—Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. The Company is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. The Company’s management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $23 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies and other commitments, please see Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. With respect to oil and gas operations in the Gulf of America, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of America to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that the Company provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company’s current ownership interests in various Gulf of America leases. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which the Company has sold Gulf of America assets or with whom the Company has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern. 51 Potential Decommissioning Obligations on Sold Properties The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of America (GOA) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOA assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise. In 2013, Apache sold its 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 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 December 31, 2025, the Company recorded an asset of $40 million representing the remaining amount the Company expects to be reimbursed from remaining security related to these decommissioning costs. Of the total asset recorded as of December 31, 2025, $21 million is reflected under the caption “Decommissioning security for sold Gulf of America properties,” and $19 million is reflected under “Other current assets” in the Company’s consolidated balance sheet. As of December 31, 2025, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $0.9 billion to $1.2 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company recorded contingent liabilities in the amounts of $881 million and $1.0 billion as of December 31, 2025, and December 31, 2024, respectively. Of the total liability recorded as of December 31, 2025, $782 million is reflected under the caption “Decommissioning contingency for sold Gulf of America properties” and $99 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected well decommissioning spread rates, derrick barge rates, planned abandonment logistics, and future cash flows of GOM Shelf, could result in a liability in excess of the amount accrued. The Company recognized $60 million of “Gains on previously sold Gulf of America properties” during 2025 to reflect the net impact of decreased estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The Company recognized losses on previously sold Gulf of America properties of $273 million and $212 million during 2024 and 2023, respectively, in the Company’s statement of consolidated operations. 52 Insurance Program The Company maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. The Company’s insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company’s insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect the Company against liability from all potential consequences and damages. Further, the Company does not have coverage in place for a variety of other risks including Gulf of America named windstorm and business interruption. The Company purchases multi-year political risk insurance from highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. Future insurance coverage for the Company’s industry could increase in cost and may include higher deductibles or retentions or a change in policy limit or additional exclusions or limitations. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable. Service agreements, including drilling contracts, generally indemnify the Company for injuries and death of the service provider’s employees, as well as subcontractors hired by the service provider, and damages to their respective property. Critical Accounting Estimates The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. The following is a discussion of the Company’s most critical accounting estimates. Long-Lived Asset Impairments Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach. Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating and administrative costs. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants. To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums. 53 Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Purchase Price Allocation Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the amounts of the identifiable net assets acquired on the acquisition date. The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. In estimating the fair values of assets acquired and liabilities assumed, the Company has made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved oil and natural gas properties. The fair value of proved oil and natural gas properties as of the acquisition date were estimated using the income approach where fair value was determined based on the expected future cash flows from estimated proved oil, natural gas, and NGL reserves and related discounted future net cash flows as of that date. Significant inputs to the fair value estimate included estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been volatility in oil, natural gas, and NGL prices, and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than projected volumes as of the acquisition date. Reserves Estimates Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Despite judgment involved in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company’s supplemental oil and gas disclosures. For more information regarding the Company’s supplemental oil and gas disclosures, refer to Note 16—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. The Company has elected not to disclose probable and possible reserves or reserve estimates in this filing. Offshore Decommissioning Contingency The Company has potential exposure to future obligations related to divested properties. For information regarding estimated potential decommissioning obligations on sold properties, please refer to “Potential Decommissioning Obligations on Sold Properties” above and in Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. 54 The Company’s estimated contingent obligation is primarily associated with the abandonment, removal and decommissioning of offshore wells and platforms in the Gulf of America. Estimating any future obligation requires significant judgment. The Company utilizes actual abandonment and decommissioning costs incurred as the basis to estimate the expected cash outflows for future obligations. Actual costs incurred often vary based on each structure’s condition, depth-of-water, type, and other similar factors, which are key considerations when estimating the remaining well and platform decommissioning obligation. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations. Changes in significant assumptions or the regulatory framework impacting the Company’s estimated liability could result in a liability in excess of the amount accrued. Asset Retirement Obligation (ARO) The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, and safety considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Income Taxes The Company’s oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company’s deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. 55