APA Corp
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
APA$44.63+2.6%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-28.
0002040266-25-000007
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
0001841666-26-000015
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 242 previous paragraphs and 220 current paragraphs.
118 unchanged; 74 reworded; 27 added; 39 removed; 11 previous and 1 current paragraphs rearranged.
Tables are not compared: 13 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (27)
Current report
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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
(5)Production volumes per day in the Company’s Wildfire field were as follows:
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
•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.
Current report
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.
Current report
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.
Removed paragraphs (39)
Previous report
•During the first quarter of 2024, the Company completed a three-well exploration program in Alaska, confirming a working petroleum system on the Company’s acreage. The Company is currently drilling an additional exploration well on this acreage. The Company holds a 50 percent ownership interest in the project.
Previous report
•During the fourth quarter of 2024, the Company entered into a new gas sales agreement which could result in improved pricing if certain production thresholds are met. The new gas sales agreement creates the potential for significant new drilling inventory with returns on par with oil.
Previous report
•During the second quarter of 2023, the Company suspended all new drilling activity in the North Sea. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company’s investment program in the North Sea is now directed toward asset safety and integrity.
Previous report
•In October 2024, the Company announced that its subsidiary reached a positive final investment decision for the first oil development, named GranMorgu, in Block 58 offshore Suriname. This development will include production from the Krabdagu and Sapakara oil discoveries. These fields, located in water depths between 100 and 1,000 meters, will be produced through a system of subsea wells connected to a floating production, storage and offloading (FPSO) unit located 150 km off the Suriname coast, with an oil production capacity of 220,000 barrels per day. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its 4-year production plateau and will feature technology that minimizes greenhouse gas emissions. Total investment is estimated at $10.5 billion, with APA’s share of the investment subject to the existing agreement with TotalEnergies to carry a portion of Apache’s appraisal and development capital. First oil is anticipated in 2028.
Previous report
NM — Not Meaningful
Previous report
NM — Not Meaningful
Previous report
Natural gas revenues for 2024 totaled $584 million, a $296 million decrease from the 2023 total of $880 million. A 32 percent decrease in average realized prices reduced 2024 revenues by $285 million compared to 2023, while 2 percent lower average daily production decreased revenues by $11 million. Average daily production in 2024 was 814 MMcf/d, with prices averaging $1.97 per Mcf. Natural gas sales accounted for 7 percent of the Company’s 2024 oil and gas production revenues and 30 percent of its worldwide production.
Previous report
GPT costs increased $98 million compared to 2023, primarily the result of increased oil and NGL production volumes in the U.S., primarily associated with the Callon acquisition, as well as increased charges for transporting gas production.
Previous report
Taxes other than income increased $63 million compared to 2023, primarily from higher severance taxes driven by increased U.S. production volumes primarily attributable to the Callon acquisition.
Previous report
Exploration expenses increased $118 million compared to 2023, primarily the result of dry hole expense associated with an exploration well in Suriname and the completion of an initial drilling campaign in Alaska, where two wells were unable to reach target objectives in the allotted seasonal time window.
Previous report
TRS costs increased $153 million compared to 2023, primarily a result of transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in 2024 primarily comprised $147 million associated with the Callon acquisition, including $76 million of separation costs and $71 million of transaction and integration costs.
Previous report
Net financing costs during 2024 increased $55 million compared to 2023, primarily driven by higher interest expense from higher average long-term debt balances.
Previous report
Income tax expense increased $741 million from an income tax benefit of $324 million during 2023 to an income tax expense of $417 million during 2024. The Company’s 2024 effective income tax rate was primarily impacted by taxes related to foreign operations. During 2023, the Company’s effective income tax rate was primarily impacted by a deferred tax benefit related to the release of a portion of its valuation allowance against U.S. deferred tax assets and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023.
Previous report
Net cash provided by operating activities for the year ended December 31, 2024 totaled $3.6 billion, up $491 million from the year ended December 31, 2023, primarily due to higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices.
Previous report
Proceeds from Term Loan Facility On April 1, 2024, the Company borrowed an aggregate $1.5 billion under a syndicated credit agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the closing of the Callon acquisition. For additional details of the credit agreement, see “Unsecured Committed Term Loan Facility”in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Previous report
Proceeds from Sale of Kinetik Shares The Company received $428 million and $228 million of cash proceeds from the sales of its Kinetik Shares during 2024 and 2023, respectively. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Previous report
Payments on Callon Credit Agreement Upon closing of the Callon acquisition, the Company financed Callon’s repayment in full of its $472 million outstanding under the Callon Credit Agreement.
Previous report
The Company may, and expects that Apache will continue to, reduce debt outstanding under its indentures from time to time.
Previous report
There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to APA or its subsidiaries or the composition of such lenders.
Previous report
There is no assurance that the financial condition of banks with lending commitments to APA or its subsidiaries will not deteriorate. The Company closely monitors the ratings of the banks in its bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.
Previous report
On April 1, 2024 (the Closing Date), APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire. As of December 31, 2024, there were $900 million in 3-Year Tranche Loans remaining outstanding under the Term Loan Credit Agreement.
Previous report
Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement.
Previous report
Borrowings under the Term Loan Credit Agreement bear interest at one of two rate options selected by APA, being either (i) an alternate base rate (as defined), plus a margin (Term Base Rate Margin) varying from 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, or (ii) an adjusted term SOFR rate (as defined), plus a margin (Term Applicable Margin) varying from 1.375% to 2.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 1.625% to 2.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date.
Previous report
Margins are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2024, Apache’s Long-Term Debt Rating applied, and the Term Base Rate Margin was 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin was 1.75% for 3-Year Tranche Loans.
Previous report
On January 15, 2025, the Company terminated commitments under the 2022 Agreements and in replacement thereof, entered into two unsecured syndicated credit agreements for general corporate purposes on terms substantially the same as those of the 2022 Agreements:
Previous report
Letters of credit are available under each 2025 Agreement for credit support needs of APA and its subsidiaries, including in respect of North Sea decommissioning obligations. As of January 15, 2025, letters of credit aggregating approximately £253 million originally issued under the 2022 GBP Agreement were deemed issued and outstanding under the 2025 GBP Agreement.
Previous report
Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt
Previous report
•APA entered into two registration rights agreements, one covering notes and debentures issued in APA’s exchange and tender offers and one covering notes issued in APA’s new notes offering (each a Registration Rights Agreement).
Previous report
These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA and Apache to use their commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA and guaranteed, if applicable, by Apache containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions or any increase in annual interest rate) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue on the principal amount of such registrable securities at a rate of 0.25% per annum for the first 90-day period beginning on the day immediately following such registration default (which rate will be increased by an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum). To the extent Apache’s guarantee of the registrable securities is terminated in accordance with the terms of such guarantee, the registered notes will not be guaranteed by Apache, the exchange offer and registration requirements with respect thereto will be the sole obligation of the Company, and Apache will automatically be released from all obligations under the applicable Registration Rights Agreement.
Previous report
The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA’s exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA’s exchange or tender offers):
Previous report
(1)The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
Previous report
(2)The Apache 2029 notes were issued under the Indenture, dated as of November 23, 1999, between Apache (as successor to Apache Finance Canada Corporation), and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
Previous report
(3)The Apache 2043 notes and the Apache 2044 notes were issued under the Senior Indenture, dated as of May 19, 2011, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).
Previous report
(4)The Apache 2027 notes, the Apache 2028 notes, the Apache 2030 notes, and the Apache 2049 notes were issued under the Indenture, dated as of August 14, 2018, between Apache and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee (an Apache Indenture).
Previous report
(5)In connection with APA’s exchange and tender offers, Apache solicited the consents of the holders of these Apache notes and debentures to amend the applicable Apache Indenture to remove certain restrictive and reporting covenants. The Apache notes and debentures are senior unsecured obligations of Apache. Apache received consents sufficient to approve the proposed amendments to the Apache Indentures with respect to the Apache March 2026 notes, the Apache 2028 notes, the Apache 2029 notes, the Apache 2030 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2043 notes, the Apache 2044 notes, the Apache 2047 debentures, the Apache 2049 notes, and the Apache 2096 debentures. As a result, Apache and the respective trustee for the Apache Indentures entered into supplemental indentures on January 10, 2025, implementing the proposed amendments effective as of that date.
Previous report
(6)The APA March 2026 notes, the APA April 2026 notes, the APA 2027 notes, the APA 2028 notes, the APA 2029 notes, the APA 2030 notes, the APA 2037 notes, the APA 2040 notes, the APA 2042 notes, the APA 2043 notes, the APA 2044 notes, the APA 2047 debentures, the APA 2049 notes, and the APA 2096 debentures were issued under the Indenture, dated as of June 30, 2021, between the Company, as issuer, and Computershare Trust Company, N.A., as successor to Wells Fargo Bank, National Association, as trustee. These APA notes and debentures were issued in APA’s exchange and tender offers for Apache’s notes and debentures.
Previous report
(7)The APA 2035 notes and the APA 2055 notes were issued under the Indenture, dated as of December 11, 2024, between the Company, as issuer, and Regions Bank, as trustee. These APA notes were issued in APA’s new notes offering to fund in part its purchase of Apache notes in APA’s cash tender offers.
Previous report
Subsequent Event—Open Market Repurchases of Apache Indenture Debt
Previous report
On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281 st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the $148 million in Bonds and $350 million in Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281 st Judicial District Court denied the Insurers’ request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the $350 million in Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refused to honor such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that sureties’ state court lawsuit against Apache was void; (2) holding that Apache’s claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys’ fees to Apache as a sanction. The parties settled their dispute in the first quarter of 2025, which resulted in, among other things, mutual releases, the retention by Apache of all amounts drawn on the Letters of Credit, and payment to Apache of $140 million under the Bonds.
Reworded paragraphs (74)
Previous wording
Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, trade 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 remains committed to its longer-term objectives: (1) to invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (3) to responsibly manage its cost structure regardless of the oil price environment.
Current wording
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.
Previous wording
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For example, the Company curtailed production in the Permian Basin in the second half of 2024 in response to weakness in Waha natural gas and NGL prices; however, in Egypt, the Company contracted an additional drilling rig in late 2024 after signing an agreement to incentivize gas exploration and production at new pricing. In 2023, the Company decided to suspend drilling activity in the North Sea, as increasing cost and tax burdens impacted the competitiveness of these assets within the Company’s portfolio. Capital investment plans have accordingly been aligned across other areas of the portfolio while maintaining a focus on the Company’s capital returns framework.
Current wording
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.
Previous wording
The Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns.
Current wording
Additionally, the Company remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns.
Previous wording
•The Company pays a quarterly dividend of $0.25 per share on its common stock.
Current wording
•The Company paid a quarterly dividend of $0.25 per share on its common stock during 2025.
Previous wording
•Beginning in the fourth quarter of 2021 and through the end of 2024, the Company has repurchased 85.3 million shares of the Company’s common stock. Subsequent to year-end 2024 and through the date of this filing on February 28, 2025, the Company repurchased 3.9 million shares, and as of February 28, 2025, the Company had remaining authorization to repurchase up to 30.9 million shares under the Company’s share repurchase programs.
Current wording
•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.
Previous wording
During 2024, the Company reported net income attributable to common stock of $804 million, or $2.27 per diluted share, compared to net income of $2.9 billion, or $9.25 per diluted share, in 2023. Net income in 2024 was primarily impacted by impairments of $1.1 billion, 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. The Company also recorded higher oil and gas revenues and associated operating expenses resulting from the Callon acquisition.
Current wording
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.
Previous wording
The Company generated $3.6 billion of cash from operating activities in 2024, which was $491 million or 16 percent higher than 2023. APA’s higher operating cash flows for 2024 were primarily driven by higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices. The Company repurchased 9.2 million shares of its common stock for $246 million and paid $353 million in dividends to APA common stockholders during 2024.
Current wording
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.
Previous wording
•Daily boe production from the Company’s U.S. assets, which increased 30 percent from 2023, accounted for 62 percent of the Company’s worldwide production during 2024. The Company averaged nine drilling rigs in the U.S. during the year, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin, and drilled and brought online 159 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. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.
Current wording
•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.
Previous wording
•In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 14 drilling rigs and drilled 62 new productive wells during 2024. During the same period, the Company averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. The 2024 gross and net production from the Company’s Egypt assets decreased 6 percent and 4 percent, respectively, from 2023.
Current wording
•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.
Previous wording
•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 include 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.
Current wording
•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.
Previous wording
•Sales of Kinetik Shares During 2022 and 2023, the Company sold a portion of its Kinetik Shares for cash proceeds of $224 million and $228 million, respectively. During the first quarter of 2024, the Company sold its remaining shares of Kinetik Class A Common Stock 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.
Current wording
•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.
Previous wording
(2)Average sales volumes from the North Sea were 33,954 boe/d, 45,476 boe/d, and 40,812 boe/d for 2024,2023, and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Current wording
(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.
Previous wording
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 2024 were down 3 percent compared to 2023, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2024 averaged $78.08 per barrel.
Current wording
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.
Previous wording
•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 per Mcf in 2024, a 61 percent decrease from an average of $1.80 per Mcf in 2023.
Current wording
•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.
Previous wording
•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.94 per Mcf in 2024, a one percent increase from an average of $2.91 per Mcf in 2023. In the fourth quarter of 2024, the Company entered into a new gas sales agreement, which could result in improved pricing if certain production thresholds are met. The new gas sales agreement, which is effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil.
Current wording
•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.
Previous wording
•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 per Mcf in 2024, a 17 percent decrease from an average of $13.02 per Mcf in 2023.
Current wording
•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.
Previous wording
Crude oil revenues for 2024 totaled $7.0 billion, a $969 million increase from the 2023 total of $6.0 billion. A 20 percent higher average daily production increased 2024 revenues by $1.2 billion compared to 2023, while a 3 percent decrease in average realized prices reduced revenues by $196 million. Average daily production in 2024 was 244 Mb/d, with prices averaging $78.08 per barrel. Crude oil sales accounted for 85 percent of the Company’s 2024 oil and gas production revenues and 54 percent of its worldwide production.
Current wording
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.
Previous wording
The Company’s worldwide crude oil production increased 41 Mb/d compared to 2023, 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., and operational downtime due to maintenance activities in the North Sea.
Current wording
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.
Previous wording
The Company’s worldwide natural gas production decreased 14 MMcf/d compared to 2023, primarily a result of natural production decline in the North Sea and U.S., reduced gas-focused activity in Egypt, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.
Current wording
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.
Previous wording
NGL revenues for 2024 totaled $646 million, a $138 million increase from the 2023 total of $508 million. A 17 percent higher average daily production increased 2024 revenues by $95 million compared to 2023, while an 8 percent increase in average realized prices increased 2024 revenues by $43 million. Average daily production in 2024 was 75 Mb/d, with prices averaging $23.37 per barrel. NGL sales accounted for 8 percent of the Company’s 2024 oil and gas production revenues and 16 percent of its worldwide production.
Current wording
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.
Previous wording
The Company’s worldwide NGL production increased 11 Mb/d compared to 2023, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, partially offset by natural production decline in the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S.
Current wording
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
Previous wording
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 million for the year ended December 31, 2024 to $1.5 billion from $894 million in 2023. Purchased oil and gas sales were partially offset by associated purchase costs of $1.0 billion and $742 million for the years ended December 31, 2024 and 2023, respectively. The increase in purchased oil and gas sales was primarily driven by increased oil volume sales coupled with activity associated with the Callon acquisition.
Current wording
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.
Previous wording
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 54 percent of the Company’s total 2024 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
Current wording
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.
Previous wording
During 2024, LOE increased $254 million, or 18 percent, compared to 2023. On a per-boe basis, LOE increased $0.48, or 5 percent, compared to 2023, from $9.68 per boe to $10.16 per boe. The increase in absolute costs was primarily driven by higher operating and labor costs and workover activity 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.
Current wording
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.
Previous wording
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:
Current wording
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:
Previous wording
Purchased oil and gas costs increased $305 million for the year ended December 31, 2024, to $1.0 billion from $742 million in 2023. The increase is primarily driven by increased oil volume purchases 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.
Current wording
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.
Previous wording
G&A expenses increased $21 million compared to 2023, primarily driven by higher overall labor costs across the Company and the Callon acquisition, partially offset by lower cash-based stock compensation expense resulting from changes in the Company’s stock price in 2024. For additional information refer to Note 13—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Current wording
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.
Previous wording
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2024 increased $735 million compared to 2023. The Company’s oil and gas property DD&A rate increased $3.32 per boe in 2024 compared to 2023, from $10.12 per boe to $13.44 per boe, driven by 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 driven by higher capital expenditures incurred in the U.S. and the Callon acquisition.
Current wording
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.
Previous wording
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. to agreed-upon proceeds for their disposition, and $18 million of inventory impairments in the North Sea and U.S. During 2023, the Company recorded $61 million of impairments, primarily in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Current wording
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.
Previous wording
On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate, effective for the period of May 26, 2022 through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. As a result, the Company recorded a deferred tax expense of $174 million and $208 million related to the remeasurement of the U.K. deferred tax liability in 2023 and 2022, respectively.
Current wording
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.
Previous wording
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, the Company accrued tax expense of $74 million, which results in a tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years.
Current wording
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.
Previous wording
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 states and foreign jurisdictions as part of its normal course of business.
Current wording
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.
Previous wording
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 remains committed to its longer-term objectives: (1) to invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (3) to responsibly manage its cost structure regardless of the oil price environment.
Current wording
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.
Previous wording
In 2025, the Company plans to invest $2.5 billion to $2.6 billion in upstream capital investment. The Company is planning an 8-rig program in the Permian Basin, with approximately four rigs in each of the Midland and Delaware basins, and a 12-rig program in Egypt, with one rig dedicated to gas appraisal and exploration. This activity set translates to a combined development capital budget for the Permian Basin and Egypt of $2.2 billion to $2.3 billion. In addition, the Company will invest approximately $200 million for Suriname development and $100 million for exploration, primarily in Alaska.
Current wording
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.
Previous wording
Based on this development capital budget, the Company anticipates production in 2025 to be slightly higher compared to 2024. This investment profile underscores the progress the Company has made on capital efficiency through the integration of Callon and stabilization of Egypt volumes. 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.
Current wording
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.
Previous wording
For the year ended December 31, 2024, the Company recognized downward reserve revisions related to decreases in commodity prices during the year. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2024, 2023, and 2022, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 17—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.
Current wording
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.
Previous wording
Proceeds from Asset Divestitures The Company received $1.6 billion and $29 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2024 and 2023, 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.
Current wording
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.
Previous wording
Additions to Oil & Gas Property Exploration and development cash expenditures were $2.9 billion and $2.3 billion for the years ended December 31, 2024 and 2023, respectively. The increase is reflective of the Company’s acquisition of Callon, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s efforts to balance workover activity in Egypt and reduce drilling activity in the North Sea as it continually assesses inventory opportunities across its diverse portfolio in 2024. The Company operated an average of 22 drilling rigs during 2024, compared to an average of 24 drilling rigs during 2023.
Current wording
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.
Previous wording
Leasehold and Property Acquisitions During 2024 and 2023, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $60 million and $20 million, respectively.
Current wording
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.
Previous wording
Payments on Term Loan Facility During 2024, the Company made payments of $600 million on its syndicated term loan credit agreement. For additional details of the credit agreement, see “Unsecured Committed Term Loan Facility”in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Current wording
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.
Showing the first 40 of 74 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
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.
Rearranged previous paragraphs (11)
Previous report — wording carried elsewhere
During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases.
Previous report — wording carried elsewhere
•One agreement was denominated in US dollars (the 2022 USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million was committed).
Previous report — wording carried elsewhere
•The second agreement was denominated in pounds sterling (the 2022 GBP Agreement) and provided for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit.
Previous report — wording carried elsewhere
APA is subject to representations and warranties, covenants, and events of default under the Term Loan Credit Agreement, such as:
Previous report — wording carried elsewhere
•A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2024, APA’s debt-to-capital ratio as calculated under the Term Loan Credit Agreement was 19 percent.
Previous report — wording carried elsewhere
•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 percent of APA’s consolidated net tangible assets or approximately $2.5 billion as of December 31, 2024.
Previous report — wording carried elsewhere
•Lenders may accelerate payment maturity and terminate lending commitments for nonpayment and other breaches; if APA or certain subsidiaries default 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 APA or certain subsidiaries.
Previous report — wording carried elsewhere
The Term Loan Credit Agreement does not permit lenders to accelerate maturity based on unspecified material adverse changes and does not have prepayment obligations in the event of a decline in credit ratings.
Previous report — wording carried elsewhere
The Company was in compliance with the terms of the Term Loan Credit Agreement as of December 31, 2024.
Previous report — wording carried elsewhere
Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities
Previous report — wording carried elsewhere
•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.