APA Corp
For the period ended Mar 31, 2025. Filed May 8, 2025.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2025 · Filed May 8, 2025
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-Q
Period ended 2024-09-30; filed 2024-11-07.
0002040266-24-000003
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-05-08.
0002040266-25-000012
Item 2. 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 159 previous paragraphs and 138 current paragraphs.
58 unchanged; 52 reworded; 26 added; 49 removed; 0 previous and 2 current paragraphs rearranged.
Tables are not compared: 11 previous and 11 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 (26)
Current report
In the first quarter of 2025, the Company announced a significant cost reduction initiative. The Company’s primary objective is to drive sustainable cost savings for the long-term and is targeting over $350 million in annualized savings by the end of 2027. This will include 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.
Current report
•APA holds approximately 750 MMBtu/d of firm capacity on various pipelines. In the first and second quarters of 2025, the Company entered into basis swap contracts purchasing NYMEX Henry Hub/Waha and selling NYMEX Henry Hub/HSC for May to December 2025 on approximately two-thirds of its firm transport capacity, thereby locking in a significant portion of cash flows associated with its marketing activities for the remainder of the year. 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 will 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
•In May 2025, the Company entered into an agreement to sell certain non-core assets and leasehold in the Permian Basin, reflecting a full exit from New Mexico, for cash consideration of $608 million, subject to customary post-closing adjustments. The transaction is expected to close late in the second of 2025, and the divested assets represent less than 5 percent of the Company’s Permian Basin oil production. The Company intends to use the proceeds from this transaction primarily for debt reduction.
Current report
•In Egypt, following the success of the gas program and the relative softening of oil prices, the Company now expects one-third of its rig activities to be gas-focused and anticipates continued strong performance for the rest of the year, with realized gas prices increasing through the period.
Current report
First-Quarter 2025 compared to First-Quarter 2024
Current report
Exploration expenses decreased $118 million from the first quarter of 2024, primarily the result of higher dry hole expenses in Alaska and unproved leasehold impairments in the first quarter of 2024 compared to the current-year period.
Current report
G&A expenses increased $5 million from the first quarter of 2024, primarily driven by higher cash-based stock compensation expense resulting from changes in expected payouts for the Company’s performance program, as well as higher labor costs from the Callon acquisition.
Current report
TRS costs increased $10 million from the first quarter of 2024, primarily associated with employee separations and other cost-saving initiatives.
Current report
Net financing costs decreased $133 million from the first quarter of 2024, reflecting gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025, partially offset by higher interest expense from higher weighted-average interest rates, compared to the same prior-year period.
Current report
On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2025, the Company recorded a deferred tax expense of $76 million related to the remeasurement of the December 31, 2024 U.K. deferred tax liability.
Current report
At this time, the Company is unable to predict to what extent recent and potential changes in trade restrictions and tariffs will impact its business. If inflationary pressures from these and other economic conditions persist or worsen, the Company may incur additional operating costs. The Company will continue to monitor the impact and consequences of these factors on its operations.
Current report
Fixed-Rate Debt Borrowings During the first three months of 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
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:
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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 were used to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.
Current report
•Each series of APA notes and debentures issued in settlement of the exchange and tender offers has 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.
Current report
•Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering are 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 is less than $1 billion.
Current 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). 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 if applicable, Apache) to use 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 at specified rates on the principal amount of such registrable securities.
Current report
The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022:
Current report
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
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.
Current report
As of December 31, 2024, there were $900 million in 3-Year Tranche Loans remaining outstanding under the Term Loan Credit Agreement. APA could at any time prepay loans under the Term Loan Credit Agreement, which it elected to do on March 10, 2025, when APA fully repaid amounts outstanding under the Term Loan Credit Agreement. The repayment was partially financed with borrowings under APA’s 2025 USD Agreement and commercial paper program.
Current report
During the first quarter of 2024, the Company recognized a $66 million loss for estimated decommissioning costs on GOA properties previously sold to Fieldwood and other GOA operators.
Removed paragraphs (49)
Previous report
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.
Previous report
Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.
Previous report
On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024.
Previous report
In the third quarter of 2024, the Company reported a net loss attributable to common stock of $223 million, or $0.60 per diluted share, compared to net income of $459 million, or $1.49 per diluted share, in the third quarter of 2023. The decrease in net income in the third quarter of 2024 compared to the third quarter of 2023 was primarily driven by $1.1 billion of impairments, which included $793 million of oil and gas property impairments in the North Sea, a $315 million impairment of assets held for sale in the Permian Basin, and $3 million inventory impairments in the North Sea. These impacts to net loss were partially offset by lower income tax expense compared to the same prior-year period.
Previous report
•Subsequent to September 30, 2024, but prior to the date of this filing, the Company entered into a new pricing agreement for incremental gas volumes produced in Egypt, making gas exploration and development more economically competitive with oil development.
Previous report
•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. 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
Third-Quarter 2024 compared to Third-Quarter 2023
Previous report
The Company’s worldwide natural gas production decreased 33.2 MMcf/d to 786.9 MMcf/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, natural production decline, and the sale of non-core assets in the U.S. These decreases were offset by the Callon acquisition coupled with increased drilling activity and recompletions in the Permian Basin.
Previous report
Year-to-Date 2024 compared to Year-to-Date 2023
Previous report
Crude Oil Crude oil revenues for the first nine months of 2024 totaled $5.1 billion, a $669 million increase from the comparative 2023 period. An 18 percent higher average daily production increased oil revenues for the 2024 period by $680 million compared to the prior-year period, while a slight decrease in average realized prices lowered oil revenues by $11 million compared to the prior-year period. Crude oil revenues accounted for 85 percent of total oil and gas production revenues and 54 percent of worldwide production for the first nine months of 2024. Crude oil prices realized during the first nine months of 2024 averaged $80.31 per barrel, compared to $80.50 per barrel in the comparative prior-year period.
Previous report
The Company’s worldwide oil production increased 35.4 Mb/d to 236.8 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were 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.
Previous report
Natural Gas Natural gas revenues for the first nine months of 2024 totaled $414 million, a $244 million decrease from the comparative 2023 period. A 35 percent decrease in average realized prices decreased natural gas revenues for the 2024 period by $232 million compared to the prior-year period, while 3 percent lower average daily production decreased revenues by $12 million compared to the prior-year period. Natural gas revenues accounted for 7 percent of total oil and gas production revenues and 30 percent of worldwide production for the first nine months of 2024.
Previous report
NGL NGL revenues for the first nine months of 2024 totaled $457 million, a $82 million increase from the comparative 2023 period. A 16 percent higher average daily production increased NGL revenues for the 2024 period by $66 million compared to the prior-year period, while a 4 percent increase in average realized prices increased revenues by $16 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2024.
Previous report
The Company’s worldwide NGL production increased 10.2 Mb/d to 72.9 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, offset by natural production decline, 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 increases were further offset by operational downtime due to maintenance activities in the North Sea.
Previous report
Exploration expenses decreased $20 million and increased $104 million from the third quarter and the first nine months of 2023, respectively. The decrease in exploration expenses for the third quarter of 2024 compared to the third quarter of 2023 was primarily the result of higher dry hole expenses in the 2023 period coupled with lower unproved leasehold impairments and exploration overhead. The increase in exploration expenses for the first nine months of 2024 compared to the first nine months of 2023 was primarily the result of dry hole expense associated with 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
G&A expenses decreased $47 million and $6 million from the third quarter and the first nine months of 2023, respectively. The decrease in G&A expenses for the third quarter and first nine months of 2024 compared to the same prior-year periods was primarily driven by higher cash-based stock compensation expense in the 2023 period resulting from changes in the Company’s stock price, partially offset by higher overall labor costs across the Company and the Callon acquisition.
Previous report
TRS costs increased $9 million and $145 million from the third quarter and the first nine months of 2023, respectively. Higher TRS costs during the third quarter and the first nine months of 2024 were primarily a result of ongoing transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.
Previous report
Impairments
Previous report
During the third quarter and the first nine months of 2024, the Company recorded $1.1 billion of impairments, which includes $793 million of oil and gas property impairments in the North Sea, $315 million impairment of assets held for sale in the Permian Basin, and $3 million of inventory impairments in the North Sea.
Previous report
During the first nine months of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Previous report
Net financing costs increased $19 million and $41 million from the third quarter and the first nine months of 2023, respectively. The increase in costs during the third quarter and the first nine months of 2024 was primarily due to higher interest expense from higher average long-term debt balances compared to the third quarter and the first nine months of 2023.
Previous report
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. The Company is continuing to evaluate the proposed regulations and their effect on the Company’s consolidated financial statements.
Previous report
During the nine months ended September 30, 2024, the Company recognized downward reserve revisions of approximately 26 percent of its year-end 2023 estimated proved reserves in the North Sea as a result of its economic assessment of its North Sea assets described in “Financial and Operational Highlights” above.
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 “Term Loan Credit Agreement”in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Previous report
Proceeds from Asset Divestitures The Company received $724 million and $29 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2024 and 2023, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Previous report
Proceeds from Sale of Kinetik Shares The Company received $428 million of cash proceeds from the sale of its remaining shares of Kinetik Class A Common Stock in March 2024. 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 I, Item 1 of this Quarterly Report on Form 10-Q.
Previous report
Payments on Callon Credit Agreement During the first nine months of 2024, the Company financed Callon’s repayment in full of the $472 million outstanding under the Callon Credit Agreement upon the Callon acquisition.
Previous report
Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon’s 6.375% Senior Notes due 2026 (Callon’s 2026 Notes), (iii) Callon’s 8.00% Senior Notes due 2028 (Callon’s 2028 Notes), and (iv) Callon’s 7.500% Senior Notes due 2030 (Callon’s 2030 Notes).
Previous report
On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon’s 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon’s 2028 Notes and Callon’s 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon’s 2028 Notes and Callon’s 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA’s obligations under the Term Loan Credit Agreement is required.
Previous report
On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:
Previous report
•Callon closed cash tender offers for Callon’s 2028 Notes and Callon’s 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.
Previous report
•Callon redeemed the outstanding $321 million principal amount of Callon’s 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.
Previous report
•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.
Previous report
On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon’s 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon’s 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.
Previous report
Critical Accounting Estimates
Previous report
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. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023. For the nine months ended September 30, 2024, the Company notes the following additional critical accounting estimate:
Previous report
Long-Lived Asset Impairments
Previous report
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.
Previous report
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, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.
Showing the first 40 of 49 passages. Open the source sections for the rest.
Reworded paragraphs (52)
Previous wording
APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business has oil and gas operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in Uruguay and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.
Current wording
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.
Previous wording
Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, 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 actions taken by foreign oil and gas producing nations, including OPEC+. 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.
Previous wording
•The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
Current wording
•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.
Previous wording
•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2024, the Company has repurchased 80.7 million shares of the Company’s common stock.
Current wording
•Beginning in the fourth quarter of 2021 and through the end of the first quarter of 2025, the Company has repurchased 89.7 million shares of the Company’s common stock. Subsequent to the quarter ended March 31, 2025 through April 30, 2025, the Company repurchased 0.6 million shares, and as of April 30, 2025, the Company had remaining authorization to repurchase up to 29.8 million shares under the Company’s share repurchase programs.
Previous wording
In the first nine months of 2024, the Company reported net income attributable to common stock of $450 million, or $1.29 per diluted share, compared to net income of $1.1 billion, or $3.50 per diluted share, in the first nine months of 2023. The decrease in net income in the first nine months of 2024 compared to the first nine months of 2023 was primarily driven by $1.1 billion of impairments recorded during the third quarter of 2024 and the related tax impacts. Net income was further impacted by higher depreciation expense, transaction and reorganization costs, and lease operating expenses, primarily a result of the Callon acquisition. These impacts to net income were partially offset by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, gain from divestitures of non-core assets, and lower income tax expense compared to the same prior-year period.
Current wording
In the first quarter of 2025, the Company reported net income attributable to common stock of $347 million, or $0.96 per diluted share, compared to net income of $132 million, or $0.44 per diluted share, in the first quarter of 2024. The increase in net income in the first quarter of 2025, compared to the first quarter of 2024, was primarily driven by increased production from drilling activity in the Permian Basin coupled with the Callon merger, as well as gains on extinguishment of debt. These increases to net income were partially offset by higher depreciation, depletion, and amortization and higher income tax expense compared to the same prior-year period.
Previous wording
The Company generated $2.6 billion of cash from operating activities during the first nine months of 2024, 23 percent higher than the first nine months of 2023. APA’s higher operating cash flows for the first nine months of 2024 were primarily driven by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, and timing of working capital items. The Company repurchased 4.6 million shares of its common stock for $146 million and paid $260 million in dividends to APA common stockholders during the first nine months of 2024.
Current wording
The Company generated $1.1 billion of cash from operating activities during the first three months of 2025, 198 percent higher than the first three months of 2024. APA’s higher operating cash flows for the first three months of 2025 were primarily driven by higher revenues as a result of increased oil and gas production, higher natural gas realized prices, and timing of working capital items. The Company repurchased 4.4 million shares of its common stock for $100 million and paid $91 million in dividends to APA common stockholders during the first three months of 2025. The Company exited the quarter with approximately $5.2 billion of long-term debt, a reduction of $754 million from year-end 2024.
Previous wording
•Daily boe production from the Company’s U.S. assets accounted for 64 percent of its total production during the third quarter of 2024 and increased 33 percent from the third quarter of 2023. Daily oil production from the Company’s U.S. assets increased 71 percent from the third quarter of 2023. During the third quarter of 2024, the Company averaged nine drilling rigs in the Permian Basin, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin. The Company brought online 48 operated wells during the quarter, of which 21 wells were associated with the Callon assets. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets. The Company expects to average 8 drilling rigs in the Permian Basin for the remainder of 2024 and into 2025.
Current wording
•Daily boe production from the Company’s U.S. assets, which increased 39 percent from the first quarter of 2024, accounted for 64 percent of the Company’s worldwide production during the first quarter of 2025. The Company averaged eight drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and four rigs in the Delaware Basin in the first quarter of 2025. The Company brought online 31 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.
Previous wording
•In Egypt, the Company continued its drilling and workover activity with a focus on oil production. The Company averaged 12 drilling rigs and drilled 15 new productive wells during the third quarter of 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. Third quarter 2024 gross production from the Company’s Egypt assets decreased 5 percent from the third quarter of 2023, and net production increased 2 percent.
Current wording
•In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 13 drilling rigs and drilled 18 new productive wells during the first quarter of 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. First quarter 2025 gross and net production from the Company’s Egypt assets decreased 5 percent and increased 3 percent, respectively, from the first quarter of 2024.
Previous wording
(4) Average sales volumes from the North Sea for the third quarters of 2024 and 2023 were 19,374 boe/d and 55,283 boe/d, respectively, and 30,607 boe/d and 47,370 boe/d for the first nine months of 2024 and 2023, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Current wording
(4) Average sales volumes from the North Sea for the first quarters of 2025 and 2024 were 36,704 boe/d and 35,078 boe/d, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Previous wording
Crude Oil Crude oil revenues for the third quarter of 2024 totaled $1.8 billion, a $92 million increase from the comparative 2023 quarter. A 23 percent higher average daily production increased third-quarter 2024 oil revenues by $251 million compared to the third quarter of 2023, while a 9 percent decrease in average realized prices decreased revenues by $159 million. Crude oil revenues accounted for 87 percent of total oil and gas production revenues and 55 percent of worldwide production in the third quarter of 2024. Crude oil prices realized in the third quarter of 2024 averaged $78.06 per barrel, compared with $86.15 per barrel in the comparative prior-year quarter.
Current wording
Crude Oil Crude oil revenues for the first quarter of 2025 totaled $1.6 billion, a $168 million increase from the comparative 2024 quarter. An 18 percent higher average daily production increased first-quarter 2025 oil revenues by $291 million compared to the first quarter of 2024, while a 9 percent decrease in average realized prices decreased revenues by $123 million. Crude oil revenues accounted for 79 percent of total oil and gas production revenues and 50 percent of worldwide production in the first quarter of 2025. Crude oil prices realized in the first quarter of 2025 averaged $73.73 per barrel, compared with $80.65 per barrel in the comparative prior-year quarter.
Previous wording
The Company’s worldwide oil production increased 48.5 Mb/d to 256.3 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline, 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 oil production increased 36.4 Mb/d to 236.5 Mb/d during the first quarter of 2025 from the comparative prior-year period, 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 in the U.S. and North Sea and the sale of non-core assets in the U.S. at the end of 2024.
Previous wording
Natural Gas Natural gas revenues for the third quarter of 2024 totaled $103 million, a $133 million decrease from the comparative 2023 quarter. A 54 percent decrease in average realized prices decreased third-quarter 2024 natural gas revenues by $128 million compared to the third quarter of 2023, while 4 percent lower average daily production decreased revenues by $5 million. Natural gas revenues accounted for 5 percent of total oil and gas production revenues and 28 percent of worldwide production during the third quarter of 2024.
Current wording
Natural Gas Natural gas revenues for the first quarter of 2025 totaled $233 million, a $57 million increase from the comparative 2024 quarter. A 17 percent higher average daily production increased first-quarter 2025 natural gas revenues by $33 million compared to the first quarter of 2024, while a 14 percent increase in average realized prices increased revenues by $24 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the first quarter of 2025.
Previous wording
The Company’s worldwide natural gas production decreased 24.7 MMcf/d to 803 MMcf/d in the first nine months of 2024 compared to the prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, reduced gas-focused activity in Egypt, natural production decline, 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 137.0 MMcf/d to 923.6 MMcf/d during the first quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in Egypt and the Permian Basin coupled with the Callon acquisition in the U.S. Natural gas production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by natural production decline in the U.S. and North Sea and the sale of non-core assets and operational downtime in the U.S.
Previous wording
NGL NGL revenues for the third quarter of 2024 totaled $158 million, a $20 million increase from the comparative 2023 quarter. An 18 percent higher average daily production increased third-quarter 2024 NGL revenues by $26 million compared to the third quarter of 2023, while a 4 percent decrease in average realized prices decreased revenues by $6 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2024.
Current wording
NGL NGL revenues for the first quarter of 2025 totaled $206 million, a $66 million increase from the comparative 2024 quarter. A 35 percent higher average daily production increased first-quarter 2025 NGL revenues by $53 million compared to the first quarter of 2024, while a 10 percent increase in average realized prices increased revenues by $13 million. NGL revenues accounted for 10 percent of total oil and gas production revenues and 17 percent of worldwide production during the first quarter of 2025.
Previous wording
The Company’s worldwide NGL production increased 12.2 Mb/d to 80 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of the Callon acquisition coupled with increased drilling activity in the Permian Basin. These increases were offset by natural production decline, 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 increases were further offset by operational downtime due to maintenance activities in the North Sea.
Current wording
The Company’s worldwide NGL production increased 20.6 Mb/d to 78.5 Mb/d during the first quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. NGL production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by natural production decline, the sale of non-core assets, and operational downtime in the U.S.
Previous wording
Purchased oil and gas sales represent volumes primarily attributable to U.S. domestic oil and gas purchases that were sold by the Company to fulfill oil and natural gas takeaway obligations and delivery commitments. Sales related to these purchased volumes totaled $473 million and $229 million during the third quarters of 2024 and 2023, respectively, and $1.0 billion and $612 million during the first nine months of 2024 and 2023, respectively. Purchased oil and gas sales were offset by associated purchase costs of $292 million and $211 million during the third quarters of 2024 and 2023, respectively, and $665 million and $558 million during the first nine months of 2024 and 2023, respectively. Gross purchased oil and gas sales values were higher in the third quarter and the first nine months of 2024 as compared to the third quarter and the first nine months of 2023, primarily driven by activity associated with the Callon acquisition.
Current wording
Purchased oil and gas sales represent volumes primarily attributable to domestic oil and gas purchases that were sold by the Company to fulfill oil and natural gas takeaway obligations and delivery commitments. Sales related to purchased volumes totaled $597 million and $203 million during the first quarters of 2025 and 2024, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $474 million and $163 million during the first quarters of 2025 and 2024, respectively. The increase in purchased oil and gas sales was primarily driven by higher oil volume sales and higher gas prices, as well as activity associated with the Callon acquisition.
Previous wording
LOE increased $24 million and $140 million compared to the third quarter and the first nine months of 2023, respectively. On a per-unit basis, LOE decreased 4 percent and increased 3 percent in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The absolute dollar increase in the third quarter and the first nine months of 2024 compared to same prior year periods was driven by higher operating and labor costs coupled with higher workover activity, primarily from the Callon acquisition.
Current wording
LOE increased $69 million from the first quarter of 2024. On a per-unit basis, LOE remained relatively flat in the first quarter of 2025 when compared to the first quarter of 2024. The increase in absolute costs was primarily driven by higher operating and labor costs coupled with higher workover activity, primarily from the Callon acquisition, and increased lifting costs in the North Sea. These increases were partially offset by the sale of non-core assets in the Permian Basin and changes in foreign exchange rates against the US dollar.
Previous wording
GPT costs increased $34 million and $83 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023, primarily driven by an increase in natural gas and NGL production volumes in the U.S. when compared to the prior-year periods.
Current wording
GPT costs increased $20 million from the first quarter of 2024, primarily driven by an increase in oil, natural gas and NGL production volumes in the U.S. and increased lifting costs in the North Sea compared to the same prior-year period.
Previous wording
Purchased oil and gas costs increased $81 million and $107 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The increase in the third quarter and the first nine months of 2024 compared to same prior-year periods was primarily driven by oil purchases from activity associated with the Callon acquisition. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill oil and natural gas takeaway obligations and delivery commitments totaling $473 million and $1.0 billion in the third quarter and the first nine months of 2024, respectively, as discussed above.
Current wording
Purchased oil and gas costs increased $311 million from the first quarter of 2024, primarily driven by increased oil volume purchases and gas volumes purchased at a higher rate coupled with activity associated with the Callon acquisition. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill oil and natural gas takeaway obligations and delivery commitments in the first quarter of 2025, as discussed above.
Previous wording
Taxes other than income increased $9 million and $42 million from the third quarter and the first nine months of 2023, respectively, primarily from higher severance taxes driven by increased production volumes in the U.S. compared to the same prior-year periods.
Current wording
Taxes other than income increased $17 million from the first quarter of 2024, primarily from higher severance taxes driven by increased production volumes in the U.S. and higher ad valorem taxes, compared to the same prior-year period.
Previous wording
Total DD&A expenses increased $177 million and $496 million from the third quarter and the first nine months of 2023, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $3.30 per boe and $3.33 per boe from the third quarter and the first nine months of 2023, respectively. The increase in DD&A on a per boe basis was driven by negative gas price-related reserve revisions in prior periods and impacts resulting from the Callon acquisition in 2024. Higher absolute dollar amount of DD&A was driven primarily by higher capital expenditures incurred in the U.S. and Egypt.
Current wording
Total DD&A expenses increased $213 million from the first quarter of 2024, primarily driven by depletion on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $2.91 per boe from the first quarter of 2024. The increase in DD&A on a per boe basis was driven by year-end 2024 negative gas price-related reserve revisions in the U.S. Permian Basin coupled with higher DD&A rates resulting from the Callon acquisition. Higher absolute dollar amounts of DD&A was directly impacted by these higher rates.
Previous wording
The Company’s effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company’s effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
Current wording
The Company’s effective income tax rate for the three months ended March 31, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. The Company’s effective income tax rate for the three months ended March 31, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations.
Previous wording
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, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.
Current wording
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.
Previous wording
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.
Current wording
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. The Company expects commodity prices to continue to be volatile in the near term as a result of macroeconomic uncertainty, current and potential tariffs or trade barriers, supply chain disruptions, and concerns over a potential economic recession. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with 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.
Previous wording
Following the completion of the Callon acquisition, the Company revised its full-year 2024 estimated upstream capital investment to approximately $2.8 billion and remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.
Current wording
The Company expects its full-year 2025 estimated upstream capital investment to be approximately $2.2 billion to $2.3 billion. Given the scale and pace of efficiency gains in the Permian drilling program, the Company is reducing its current eight-rig program to six rigs by the end of the second quarter of 2025. The Company is planning a 12-rig program in Egypt, with one rig dedicated to gas appraisal and exploration. This activity set equates to a combined development capital budget for the Permian Basin, Egypt, and North Sea of $2.0 billion to $2.1 billion. In addition, the Company will invest approximately $200 million for Suriname development and $75 million for other exploration activities. APA remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.
Previous wording
Net cash provided by operating activities during the first nine months of 2024 totaled $2.6 billion, $485 million higher from the first nine months of 2023, primarily due to higher revenues from increased oil and gas production and timing of working capital items.
Current wording
Net cash provided by operating activities during the first three months of 2025 totaled $1.1 billion, $728 million higher from the first three months of 2024, primarily due to higher revenues from increased oil and gas production, higher natural gas prices, and timing of working capital items.
Previous wording
Proceeds from Commercial Paper and Revolving Credit Facilities, Net As of September 30, 2024, outstanding borrowings under the Company’s commercial paper and U.S. dollar denominated syndicated credit facility were $562 million, an increase of $190 million since December 31, 2023. During the nine months ended September 30, 2023, the Company had net borrowings of $202 million under the Company’s U.S. dollar denominated syndicated credit facility.
Current wording
Proceeds from Commercial Paper and Revolving Credit Facilities, Net As of March 31, 2025, outstanding borrowings under the Company’s commercial paper and U.S. dollar denominated syndicated credit facility were $766 million, an increase of $433 million since December 31, 2024. During the first three months of 2024, the Company had no net borrowings under the Company’s U.S. dollar denominated syndicated credit facility.
Previous wording
Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $2.2 billion and $1.7 billion during the first nine months of 2024 and 2023, respectively. The increase in capital investment compared to the prior-year period 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. The Company operated an average of approximately 23 drilling rigs during the first nine months of 2024, compared to an average of approximately 24 drilling rigs during the first nine months of 2023.
Current wording
Additions to Oil & Gas Property During the first three months of 2025 and 2024, exploration and development cash expenditures were $777 million and $467 million, respectively. The increase in capital investment compared to the prior-year period is reflective of the properties acquired from the Callon acquisition, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s decision to eliminate drilling activity in the North Sea. The Company operated an average of approximately 22 drilling rigs during the first three months of 2025, compared to an average of approximately 23 drilling rigs during the first three months of 2024.
Previous wording
Leasehold and Property Acquisitions During the first nine months of 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 $64 million and $11 million, respectively.
Current wording
Leasehold and Property Acquisitions During the first three months of 2025 and 2024, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $13 million and $63 million, respectively.
Previous wording
Payments on Term Loan Facility During the first nine months of 2024, the Company made a payment of $500 million on its syndicated credit agreement. For additional details of the credit agreement, see “Term Loan Credit Agreement”in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Current wording
Payments on Term Loan Facility During the first three months of 2025, the Company made a payment of $900 million 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.
Previous wording
Payments on Fixed-Rate Debt During the first nine months of 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 amount of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.
Current wording
Payments on Fixed-Rate Debt During the first three months of 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures of Apache and made open market repurchases for an aggregate cash payment amount of $905 million, reflecting principal amounts, discount to par, and associated fees.
Previous wording
The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.
Current wording
The Company may, and expects that Apache will continue to, reduce debt outstanding under its indentures from time to time.
Previous wording
Dividends Paid to APA Common Stockholders The Company paid $260 million and $232 million during the first nine months of 2024 and 2023, respectively, for dividends on its common stock.
Current wording
Dividends Paid to APA Common Stockholders During the first three months of 2025 and 2024, the Company paid $91 million and $76 million, respectively, for dividends on its common stock.
Previous wording
Distributions to Noncontrolling Interest Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $233 million and $154 million during the first nine months of 2024 and 2023, respectively, in cash distributions to Sinopec.
Current wording
Distributions to Noncontrolling Interest Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. During the first three months of 2025 and 2024, the Company paid $126 million and $70 million, respectively, in cash distributions to Sinopec.
Previous wording
Treasury Stock Activity, net In the first nine months of 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share and an aggregate purchase price of approximately $146 million, and as of September 30, 2024, the Company had remaining authorization to repurchase 39.3 million shares. In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share and an aggregate purchase price of approximately $208 million.
Current wording
Treasury Stock Activity, net In the first three months of 2025, the Company repurchased 4.4 million shares at an average price of $22.87 per share and an aggregate purchase price of approximately $100 million, and as of March 31, 2025, the Company had remaining authorization to repurchase 30.4 million shares. In the first three months of 2024, the Company repurchased 3.0 million shares at an average price of $33.27 per share and an aggregate purchase price of approximately $101 million.
Previous wording
Cash and Cash Equivalents As of September 30, 2024, the Company had $64 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.
Current wording
Cash and Cash Equivalents As of March 31, 2025, the Company had $67 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.
Previous wording
Debt As of September 30, 2024, the Company had $6.4 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility and commercial paper borrowings, and finance lease obligations. As of September 30, 2024, current debt included $2 million of finance lease obligations.
Current wording
Debt As of March 31, 2025, the Company had $5.4 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache, credit facility and/or commercial paper borrowings, and finance lease obligations. As of March 31, 2025, current debt included $2 million of finance lease obligations and $129 million of APA and Apache notes coming due within the next year.
Previous wording
During the nine months ended September 30, 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. The Company recognized a $9 million gain on these repurchases.
Current wording
Indenture Debt Activity During the quarter ended March 31, 2025, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $55 million for an aggregate purchase price of $50 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $7 million. The Company recognized a $7 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.
Previous wording
•One agreement is denominated in US dollars (the 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 currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
Current wording
•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.
Previous wording
•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.
Current wording
•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.
Showing the first 40 of 52 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
•One agreement was denominated in US dollars (the 2022 USD Agreement) and provided 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).
Current report — wording carried from 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.