APA Corp
For the period ended Mar 31, 2026. Filed May 7, 2026.
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, 2026 · Filed May 7, 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-Q
Period ended 2025-09-30; filed 2025-11-06.
0001841666-25-000031
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-07.
0001841666-26-000034
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 149 previous paragraphs and 117 current paragraphs.
58 unchanged; 49 reworded; 10 added; 40 removed; 2 previous and 0 current paragraphs rearranged.
Tables are not compared: 11 previous and 10 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 (10)
Current report
•From year-end 2021 through the date of this filing, the Company has repaid $3.6 billion of long-term debt, including $555 million repaid subsequent to the end of the first quarter of 2026.
Current report
First-Quarter 2026 compared to First-Quarter 2025
Current report
GPT costs decreased $13 million from the first quarter of 2025, primarily driven by a decrease in production volumes in the U.S. compared to the same prior-year period.
Current report
Purchased oil and gas costs decreased $399 million from the first quarter of 2025, primarily driven by decreased oil and gas volume purchases following the expiration of certain third-party contracts in 2025 and gas volumes purchased at significantly lower prices in the Permian Basin.
Current report
Exploration expenses decreased $4 million from the first quarter of 2025, primarily the result of lower exploration overhead and geological and geophysical expense in the first quarter of 2026 compared to the same prior-year period.
Current report
The Company plans to invest approximately $2.1 billion in upstream capital investment in 2026. The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its planned capital investment program. For the rest of 2026, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves, subject to prevailing commodity prices. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserves economically.
Current report
Payments on Fixed-Rate Debt During the first three months of 2026, the Company repaid in cash on maturity $79 million of long-term debt due during the quarter, plus accrued and unpaid interest to the maturity date.
Current report
Indenture Debt Activity On March 15, 2026, APA and Apache repaid in cash on maturity the outstanding $79 million aggregate principal amount of their respective 7.70% Notes due 2026, plus accrued and unpaid interest to the maturity date.
Current report
Subsequent Events—Indenture Debt Activity On April 6, 2026, APA and Apache fully redeemed their respective 4.875% Notes due 2027 and 4.375% Notes due 2028. Note holders were paid an aggregate $425 million in cash (comprised of outstanding principal amounts and make-whole premiums), plus accrued and unpaid interest to the redemption date.
Current report
On April 15, 2026, APA and Apache repaid in cash on maturity the outstanding $132 million aggregate principal amount of their respective 7.95% Notes due 2026, plus accrued and unpaid interest to the maturity date.
Removed paragraphs (40)
Previous 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 consistent year-over-year oil production. Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending, with minimal anticipated impact on 2026 oil volumes.
Previous report
•The Government of Egypt awarded the Company an additional two million net exploration acreage 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, nearly eliminating EGPC’s past due receivables.
Previous report
Third-Quarter 2025 compared to Third-Quarter 2024
Previous report
Year-to-Date 2025 compared to Year-to-Date 2024
Previous report
Crude Oil Crude oil revenues for the first nine months of 2025 totaled $4.5 billion, a $685 million decrease from the comparative 2024 period. A 14 percent decrease in average realized prices lowered oil revenues for the 2025 period by $726 million compared to the same prior-year period, while higher sales volumes, despite relatively flat average daily production, increased oil revenues by $41 million. Crude oil revenues accounted for 80 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2025. Crude oil prices realized during the first nine months of 2025 averaged $68.94 per barrel, compared to $80.31 per barrel in the comparative prior-year period.
Previous report
The Company’s worldwide oil production stayed relatively flat in the first nine months of 2025 compared to the same prior-year period, the 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 and downtime recovery in the North Sea.
Previous report
Natural Gas Natural gas revenues for the first nine months of 2025 totaled $609 million, a $195 million increase from the comparative 2024 period. A 30 percent increase in average realized prices increased natural gas revenues for the 2025 period by $123 million compared to the same prior-year period, while 14 percent higher average daily production increased revenues by $72 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production for the first nine months of 2025.
Previous report
The Company’s worldwide natural gas production increased 113.7 MMcf/d to 917 MMcf/d in the first nine months of 2025 compared to the same 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., and downtime recovery in the North Sea. 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 offset by the sale of non-core assets in the U.S., natural production decline in the U.S. and North Sea, and operational downtime in the U.S.
Previous report
NGL NGL revenues for the first nine months of 2025 totaled $501 million, a $44 million increase from the comparative 2024 period. A 7 percent higher average daily production increased NGL revenues for the 2025 period by $33 million compared to the same prior-year period, while a 3 percent increase in average realized prices increased revenues by $11 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production for the first nine months of 2025.
Previous report
The Company’s worldwide NGL production increased 5.0 Mb/d to 77.8 Mb/d in the first nine months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. and downtime recovery in the North Sea. 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 offset by the sale of non-core assets in the U.S., natural production decline in the U.S. and North Sea, and operational downtime in the U.S.
Previous report
The Company’s GPT expenses were as follows:
Previous report
GPT costs decreased $13 million and $10 million from the third quarter and the first nine months of 2024, respectively. The decrease in third-party costs for the third quarter of 2025 was primarily driven by decreased oil and NGL production volumes in the U.S. partially offset by production volumes resulting from downtime recovery in the North Sea compared to the same prior-year period. The decrease in third-party costs for the first nine months of 2025 was driven by decreases in average transportation rates compared to the same prior-year period.
Previous report
Purchased oil and gas costs decreased $108 million and increased $297 million from the third quarter and the first nine months of 2024, respectively. The decrease in the third quarter of 2025 was primarily driven by decreased oil volume purchases, compared to the same prior-year periods. The increase in the first nine months of 2025 was 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 third quarter and first nine months of 2025, as discussed above.
Previous report
Exploration expenses decreased $7 million and $153 million from the third quarter and the first nine months of 2024, respectively. The decrease in expenses for the third quarter of 2025 was primarily driven by higher dry hole and seismic expenses in Alaska in the prior-year period. The decrease in expenses for the first nine months of 2025 was primarily driven by higher dry hole expenses in Alaska and Suriname in the prior-year period.
Previous 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. The Company does not expect this guidance to 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 the third quarter of 2025, the Company has recorded a current tax benefit of $60 million, fully offset by a deferred tax expense of the same amount.
Previous report
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 report
The Company expects its full-year 2025 estimated upstream capital investment to be approximately $2.3 billion to $2.4 billion. During the third quarter of 2025, continued efficiency gains allowed the Company to further reduce the Permian rig count to five, while increasing oil production outlook for fourth quarter. In Egypt, following the ongoing momentum of the Company’s gas program and the relative softening of oil prices, the Company expects one-third of its activities to be gas-focused. 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 report
Fixed-Rate Debt Borrowings During the first nine 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.
Previous report
Proceeds from Asset Divestitures The Company received $590 million and $724 million in proceeds from the divestitures of certain non-core assets during the first nine months of 2025 and 2024, 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
Payments on Commercial Paper and Revolving Credit Facilities, Net During the first nine months of 2025, the Company made net payments of $333 million on its commercial paper and U.S. dollar denominated syndicated credit facility borrowings. As of September 30, 2025, there were no outstanding borrowings under each of the Company’s commercial paper and U.S. dollar denominated syndicated credit facility.
Previous report
Payments on Term Loan Facility During the first nine months of 2025 and 2024, the Company made a payment of $900 million and $500 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.
Previous report
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.
Previous report
Treasury Stock Activity, net In the first nine months of 2025, the Company repurchased 10.2 million shares at an average price of $21.08 per share and an aggregate purchase price of approximately $215 million, and as of September 30, 2025, the Company had remaining authorization to repurchase 24.6 million shares. 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.
Previous report
Additionally, 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.
Previous 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:
Previous 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.
Previous 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.
Previous 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.
Previous report
•Each series of APA notes and debentures issued in settlement of the exchange and tender offers had the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.
Previous report
•Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering were fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than $1 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.
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). 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 (collectively, the Unregistered Notes). Each Registration Rights Agreement required APA to use commercially reasonable efforts to cause to be filed and become effective under the Securities Act, a registration statement with respect to a registered offer to exchange each series of Unregistered Notes for registered notes and debentures issued by APA containing terms substantially identical in all material respects to the applicable series of Unregistered Notes (except that the registered notes and debentures do not contain terms with respect to transfer restrictions, registration rights applicable to the Unregistered Notes, or any increase in annual interest rate for failure to comply with such registration rights). In August 2025, APA filed such registration statement, and it became effective. On September 18, 2025, APA settled the exchange offers covered by such registration statement, issuing registered notes and debentures in the same aggregate principal amount as the Unregistered Notes accepted for exchange and canceled. Of the $3.6 billion aggregate principal amount of Unregistered Notes covered by the exchange offers, 99 percent was exchanged for registered notes and debentures, and the remaining Unregistered Notes remained outstanding.
Previous report
Apache guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.
Previous report
The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022:
Previous 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.
Previous report
Payment of CP Notes was unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on June 20, 2025.
Previous report
Unsecured Committed Term Loan Facility On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon upon closings of APA’s acquisition of Callon and the Term Loan Credit Agreement. Of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans).
Previous report
On April 1, 2024, APA acquired Callon and 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.
Previous 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.
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. 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.
Previous report
The Company recognized $83 million in the first six months of 2024, respectively, of losses for estimated decommissioning costs on GOA properties previously sold to Fieldwood and other GOA operators.
Reworded paragraphs (49)
Previous 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.
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 and duration of armed conflicts involving Iran, Russia, Ukraine, Israel, Lebanon, and Gaza, 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
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 $350 million in annualized savings across G&A, LOE, and capital by the end of 2025 and an additional $50 million to $100 million by the end of 2026. 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 wording
In the first quarter of 2026, the Company continued its cost reduction efforts to drive sustainable cost savings for the long-term. The Company remained focused on reducing overhead costs, improving the capital cost structure for its drilling, completions, and facility investments, and driving efficiencies of day-to-day field operating practices. The Company expects an additional $100 million of annualized savings to be achieved by the end of 2026, adding to the $350 million of annualized savings across G&A, LOE, and capital captured during the prior year.
Previous wording
•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2025, the Company has repurchased 95.5 million shares of the Company’s common stock. Subsequent to the quarter ended September 30, 2025 through October 31, 2025, the Company repurchased 1.0 million shares, and as of October 31, 2025, the Company had remaining authorization to repurchase up to 23.6 million shares under the Company’s share repurchase programs.
Current wording
•Beginning in the fourth quarter of 2021 and through the end of the first quarter of 2026, the Company has repurchased 98.2 million shares of the Company’s common stock.
Previous wording
In the third quarter of 2025, the Company reported net income attributable to common stock of $205 million, or $0.57 per diluted share, compared to a net loss of $223 million, or $0.60 per diluted share, in the third quarter of 2024. In the first nine months of 2025, the Company reported net income attributable to common stock of $1.2 billion, or $3.20 per diluted share, compared to net income of $450 million, or $1.29 per diluted share, in the first nine months of 2024. The increase in net income in the third quarter and the first nine months of 2025 compared to the same prior-year periods was primarily driven by $1.1 billion of impairments recorded in the prior-year period. Lower operating expenses in the third quarter and first nine months of 2025, resulting largely from focused cost-reduction efforts undertaken in 2025, further contributed to the increase in net income.
Current wording
In the first quarter of 2026, the Company reported net income attributable to common stock of $446 million, or $1.26 per diluted share, compared to net income of $347 million, or $0.96 per diluted share, in the first quarter of 2025. The increase in net income in the first quarter of 2026, compared to the first quarter of 2025, was primarily driven by improved margins on third-party purchased oil and gas activity and lower operating expenses driven by prior year cost savings initiatives.
Previous wording
The Company generated $3.7 billion of cash from operating activities during the first nine months of 2025, 45 percent higher than the first nine months of 2024. APA’s higher operating cash flows for the first nine months of 2025 were primarily driven by lower overall expenses, collection of outstanding receivables, and timing of other working capital items. The Company repurchased 10.2 million shares of its common stock for $215 million and paid $271 million in dividends to APA common stockholders during the first nine months of 2025. The Company exited the quarter with approximately $4.5 billion of debt, a reduction of $1.6 billion from year-end 2024.
Current wording
The Company generated $554 million of cash from operating activities during the first three months of 2026, 49 percent lower than the first three months of 2025. APA’s lower operating cash flows for the first three months of 2026 were primarily driven by the collection of outstanding Egypt receivables in the prior year and timing of other working capital items. The Company paid $88 million in dividends to APA common stockholders during the first three months of 2026. The Company also repaid $79 million of long-term debt that matured during the quarter.
Previous wording
•Daily boe production from the Company’s U.S. assets, which decreased 7 percent from the third quarter of 2024, accounted for 61 percent of the Company’s worldwide production during the third quarter of 2025. The Company averaged six drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and two rigs in the Delaware Basin in the third quarter of 2025. The Company brought online 42 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent the key growth area for its U.S. assets.
Current wording
•Daily boe production from the Company’s U.S. assets, which decreased 11 percent from the first quarter of 2025, accounted for 60 percent of the Company’s worldwide production during the first quarter of 2026. The Company averaged five drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and one rig in the Delaware Basin in the first quarter of 2026. The Company brought online 19 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent a key growth area for the U.S. assets.
Previous wording
•APA holds approximately 750,000 MMBtu/d of firm capacity on various pipelines. As of September 30, 2025, the Company had open basis swap contracts which purchased NYMEX Henry Hub/Waha and sold NYMEX Henry Hub/HSC on approximately two-thirds of its firm transport capacity for 2025 and including swap contracts entered into subsequent to September 30, 2025, approximately one-third for 2026, thereby locking in a significant portion of cash flows associated with its marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.
Current wording
•APA holds approximately 750,000 MMBtu/d of firm capacity on various pipelines in the Permian Basin. As of March 31, 2026, the Company had open basis swap contracts which purchased Waha and sold NYMEX Henry Hub on approximately one-third of its firm transport capacity for 2026, thereby locking in a significant portion of cash flows associated with its gas marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.
Previous wording
•In Egypt, the Company averaged 12 drilling rigs and drilled 17 new productive wells during the third 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. Third quarter 2025 gross and net production from the Company’s Egypt assets decreased 1 percent and increased 7 percent, respectively, from the third quarter of 2024.
Current wording
•In Egypt, the Company averaged 12 drilling rigs and drilled 16 new productive wells during the first quarter of 2026. The Company also averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. First quarter 2026 gross and net production from the Company’s Egypt assets increased 2 percent and 8 percent, respectively, from the first quarter of 2025.
Previous wording
•In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company expects one-third of its 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 wording
•In Egypt, following the success of the 2025 gas program, the Company expects approximately one-half 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.
Previous wording
(1) Gross oil, natural gas, and NGL production in Egypt were as follows:
Current wording
(1) Gross production volumes in Egypt were as follows:
Previous wording
(4) Average sales volumes from the North Sea for the third quarters of 2025 and 2024 were 32,832 boe/d and 19,374 boe/d, respectively, and 32,503 boe/d and 30,607 boe/d for the first nine months of 2025 and 2024, 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 2026 and 2025 were 28,275 boe/d and 36,704 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 2025 totaled $1.5 billion, a $327 million decrease from the comparative 2024 quarter. A 14 percent decrease in average realized prices decreased third-quarter 2025 oil revenues by $245 million compared to the third quarter of 2024, while 9 percent lower average daily production decreased revenues by $82 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 51 percent of worldwide production in the third quarter of 2025. Crude oil prices realized in the third quarter of 2025 averaged $67.43 per barrel, compared with $78.06 per barrel in the comparative prior-year quarter.
Current wording
Crude Oil Crude oil revenues for the first quarter of 2026 totaled $1.6 billion, a $44 million increase from the comparative 2025 quarter. A 7 percent increase in average realized prices increased first-quarter 2026 oil revenues by $107 million compared to the first quarter of 2025, while 4 percent lower average daily sales volumes decreased revenues by $63 million. Crude oil accounted for 85 percent of total oil and gas production revenues and 52 percent of worldwide production in the first quarter of 2026.
Previous wording
The Company’s worldwide oil production decreased 22.1 Mb/d to 234.2 Mb/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of the sale of non-core assets in the U.S. and natural production decline in the U.S. and the North Sea. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.
Current wording
The Company’s worldwide oil production decreased 4.5 Mb/d to 232 Mb/d during the first quarter of 2026 from the comparative prior-year period, primarily a result of natural production decline in the U.S. and North Sea, operational downtime, and the sale of non-core assets in the U.S. Also during the first quarter of 2026, the timing of liftings in the North Sea drove an additional 4.4 Mb/d decrease in sales volumes compared to the same prior-year period. These decreases were partially offset by drilling activity in the Permian Basin and improved well performance in the North Sea.
Previous wording
Natural Gas Natural gas revenues for the third quarter of 2025 totaled $192 million, an $89 million increase from the comparative 2024 quarter. A 57 percent increase in average realized prices increased third-quarter 2025 natural gas revenues by $60 million compared to the third quarter of 2024, while 18 percent higher average daily production increased revenues by $29 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2025.
Current wording
Natural Gas Natural gas revenues for the first quarter of 2026 totaled $157 million, a $76 million decrease from the comparative 2025 quarter. A 25 percent decrease in average realized prices, driven by periods of negative pricing across the Permian Basin, decreased first-quarter 2026 natural gas revenues by $57 million compared to the first quarter of 2025, while 11 percent lower average daily production decreased gas revenues by $19 million. Natural gas accounted for 8 percent of total oil and gas production revenues and 31 percent of worldwide production during the first quarter of 2026.
Previous wording
The Company’s worldwide natural gas production increased 145.3 MMcf/d to 932.2 MMcf/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in Egypt and downtime recovery in the North Sea. Natural gas production was also higher as a result of lower volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by the sale of non-core assets in the U.S. and natural production decline in the U.S. and North Sea.
Current wording
The Company’s worldwide natural gas production decreased 99.1 MMcf/d to 824.4 MMcf/d during the first quarter of 2026 from the comparative prior-year period, primarily a result of increased volume curtailments at Alpine High compared with the 2025 period in response to extreme Waha basis differentials, including periods of negative pricing. These curtailments were undertaken to mitigate the economic impact of selling gas into constrained markets at uneconomic or negative prices. Natural gas production was also lower as a result of the sale of non-core assets and operational downtime in the U.S., and natural production decline in the U.S. and North Sea. These decreases were partially offset by drilling activity in Egypt and the Permian Basin, with Egypt also benefitting from higher realized natural gas prices and improved well performance in the North Sea.
Previous wording
NGL NGL revenues for the third quarter of 2025 totaled $142 million, a $16 million decrease from the comparative 2024 quarter. A 7 percent lower average daily production decreased third-quarter 2025 NGL revenues by $11 million compared to the third quarter of 2024, while a 3 percent decrease in average realized prices decreased revenues by $5 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production during the third quarter of 2025.
Current wording
NGL NGL revenues for the first quarter of 2026 totaled $141 million, a $65 million decrease from the comparative 2025 quarter. A 27 percent decrease in average realized prices decreased first-quarter 2026 NGL revenues by $56 million compared to the first quarter of 2025, while 7 percent lower average daily production decreased revenues by $9 million. NGLs accounted for 7 percent of total oil and gas production revenues and 17 percent of worldwide production during the first quarter of 2026.
Previous wording
The Company’s worldwide NGL production decreased 5.8 Mb/d to 74.2 Mb/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of the sale of non-core assets in the U.S. and natural production decline in the U.S. and the North Sea. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.
Current wording
The Company’s worldwide NGL production decreased 5.6 Mb/d to 73.0 Mb/d during the first quarter of 2026 from the comparative prior-year period, primarily a result of increased volume curtailments and weather shut-ins compared with the 2025 period. NGL production was also lower as a result of the sale of non-core assets and operational downtime in the U.S. and natural production decline in the U.S. and North Sea. These decreases were partially offset by drilling activity in the Permian Basin and improved well performance in the North Sea.
Previous 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 $311 million and $473 million during the third quarters of 2025 and 2024, respectively, and $1.4 billion and $1.0 billion during the first nine months of 2025 and 2024, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $184 million and $292 million during the third quarters of 2025 and 2024, respectively, and $962 million and $665 million, respectively, during the first nine months of 2025 and 2024, respectively. Gross purchased oil and gas sales values were lower in the third quarter, primarily driven by lower oil volume sales and lower oil prices. Gross purchased oil and gas sales values were higher in the first nine months of 2025, primarily driven by higher natural gas prices and activity associated with the Callon acquisition.
Current wording
Purchased oil and gas sales represent volumes attributable to domestic oil and gas purchases that were sold by the Company primarily to fulfill oil and natural gas takeaway obligations and commitments, including deliveries under international LNG price-based contracts. Sales related to purchased volumes totaled $385 million and $597 million during the first quarters of 2026 and 2025, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $75 million and $474 million during the first quarters of 2026 and 2025, respectively. The higher margin between purchased volume sales compared to costs realized during the first quarter of 2026 was primarily attributable to extreme Permian Basin natural gas price differentials with Houston Ship Channel pricing.
Previous wording
LOE decreased $42 million and $66 million from the third quarter and the first nine months of 2024, respectively. On a per-unit basis, LOE decreased 11 percent in each of the third quarter and the first nine months of 2025, respectively, when compared to the third quarter and the first nine months of 2024. The decrease in absolute costs when compared to the same prior-year periods 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. The decrease in absolute costs for the first nine months of 2025 was partially offset by a full year of operating cost activity related to the Callon transaction.
Current wording
LOE decreased $45 million from the first quarter of 2025. On a per-unit basis, LOE decreased 5 percent in the first quarter of 2026 when compared to the first quarter of 2025. The decrease in absolute costs was primarily driven by the sale of non-core assets in the Permian Basin and continued cost reduction efforts across all operating areas.
Previous wording
Taxes other than income decreased $19 million and $26 million from the third quarter and the first nine months of 2024, respectively, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes.
Current wording
Taxes other than income decreased $17 million from the first quarter of 2025, primarily from lower severance taxes driven by decreased production volumes in the U.S. and lower ad valorem taxes compared to the same prior-year period.
Previous wording
G&A expenses increased $3 million and decreased $11 million from the third quarter and the first nine months of 2024, respectively. The increase in expenses for the third quarter of 2025 compared to the same prior-year period was primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price and expected payouts for the Company’s performance programs, which were largely offset by the impacts of focused cost-reduction efforts on personnel and other overhead expenses. The decrease in expenses for the first nine months of 2025 compared with the prior-year period was primarily the result of these focused cost-reduction efforts.
Current wording
G&A expenses increased $17 million from the first quarter of 2025, primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price during the period, partially offset by impacts from cost-reduction efforts on personnel and other overhead expenses.
Previous wording
TRS costs increased $4 million and decreased $90 million from the third quarter and the first nine months of 2024, respectively. TRS costs for 2025 were primarily associated with employee separations and other cost-saving initiatives, while TRS costs for 2024 comprised primarily expenses associated with the Callon merger.
Current wording
TRS costs decreased $30 million from the first quarter of 2025, primarily associated with employee separations and other cost-saving initiatives that occurred during the first quarter of 2025.
Previous wording
Total DD&A expenses decreased $30 million and increased $125 million from the third quarter and the first nine months of 2024, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.81 per boe and increased $0.29 per boe from the third quarter and the first nine months of 2024, respectively. The decrease in DD&A absolute expenses and on a per boe basis for the third quarter of 2025 was primarily driven by lower DD&A rates resulting from the sale of non-core assets in the Permian Basin. For the first nine months of 2025, the Company’s higher DD&A rate on its oil and gas properties on a per boe basis was driven by year-end 2024 negative gas price-related reserve revisions in the U.S. Permian Basin. Higher absolute dollar amounts of DD&A for the first nine months of 2025 were directly impacted by these higher rates.
Current wording
Total DD&A expenses decreased $90 million from the first quarter of 2025. The Company’s DD&A rate on its oil and gas properties decreased $1.21 per boe from the first quarter of 2025. The decrease in DD&A expense on an absolute basis and on a per boe basis was primarily driven by lower DD&A rates resulting from the sale of non-core assets in the Permian Basin during 2025.
Previous wording
Net financing costs decreased $54 million and $221 million from the third quarter and the first nine months of 2024, respectively. The lower overall interest expense was primarily a result of lower outstanding credit facility borrowings compared to the prior-year periods. The decrease in net financing costs during the first nine months of 2025 was further driven by gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025.
Current wording
Net financing costs increased $114 million from the first quarter of 2025, primarily the result of gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025, partially offset by a decrease in interest expense from the associated lower long-term debt balance.
Previous wording
The Company’s effective income tax rate for the three and nine months ended September 30, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. The Company’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.
Current wording
The Company’s effective income tax rate for the three months ended March 31, 2026 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. The Company’s effective income tax rate for the 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.
Previous wording
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 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 wording
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.
Previous wording
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. The Company does not expect the OBBBA to 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 the third quarter of 2025, the Company has recorded a current tax benefit of $29 million fully offset by a deferred tax expense of the same amount.
Current wording
On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for corporate alternative minimum tax (CAMT) purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2026, as impacts to current tax expense are offset by impacts to deferred tax expense.
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. 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.
Current wording
Operating cash flows are the Company’s principal source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. The Company expects commodity prices to continue to be volatile in the near term as a result of geopolitical instability and tensions, including in the Middle East, macroeconomic uncertainty, current and potential tariffs or trade barriers, supply chain disruptions, and concerns over a potential economic recession. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
Previous wording
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 wording
At this time, the Company is unable to predict to what extent ongoing international conflicts in the Middle East, Russia, and Ukraine, and potential changes in trade restrictions and tariffs will impact its business. If inflationary pressures from these and other economic conditions persist or worsen, the Company may incur additional operating costs. The Company will continue to monitor the impact and consequences of these factors on its operations.
Previous wording
Net cash provided by operating activities during the first nine months of 2025 totaled $3.7 billion, $1.1 billion higher from the first nine months of 2024, primarily due to collection of outstanding receivables, lower overall expenses, and timing of other working capital items.
Current wording
Net cash provided by operating activities during the first three months of 2026 totaled $554 million, $542 million lower from the first three months of 2025, primarily due to lower revenues from decreased oil and gas production, lower natural gas prices, collection of outstanding Egypt receivables in 2025, and timing of other working capital items.
Previous wording
Additions to Oil & Gas Property During the first nine months of 2025 and 2024, exploration and development cash expenditures were $2.2 billion in each period. The 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 approximately 20 drilling rigs during the first nine months of 2025, compared to an average of approximately 23 drilling rigs during the first nine months of 2024.
Current wording
Additions to Oil & Gas Property During the first three months of 2026 and 2025, exploration and development cash expenditures were $542 million and $777 million, respectively. The decrease in capital investment compared to the prior-year period is directly related to the Company’s efficiency gains on drilling and completion activities in the Permian Basin and Egypt. The Company operated an average of approximately 17 drilling rigs during the first three months of 2026, compared to an average of approximately 22 drilling rigs during the first three months of 2025.
Previous wording
Leasehold and Property Acquisitions During the first nine months of 2025 and 2024, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $20 million and $64 million, respectively.
Current wording
Leasehold and Property Acquisitions During the first three months of 2026 and 2025, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million and $13 million, respectively.
Previous wording
Payments on Fixed-Rate Debt During the first nine 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 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 wording
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
Dividends Paid to APA Common Stockholders During the first nine months of 2025 and 2024, the Company paid $271 million and $260 million, respectively, for dividends on its common stock.
Current wording
Dividends Paid to APA Common Stockholders During the first three months of 2026 and 2025, the Company paid $88 million and $91 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. During the first nine months of 2025 and 2024, the Company paid $390 million and $233 million, 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 2026 and 2025, the Company paid $65 million and $126 million, respectively, in cash distributions to Sinopec.
Previous wording
Cash and Cash Equivalents As of September 30, 2025, the Company had $475 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, 2026, the Company had $293 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, 2025, the Company had $4.5 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache and finance lease obligations. As of September 30, 2025, current debt included $2 million of finance lease obligations and $211 million of APA and Apache notes coming due within the next year.
Current wording
Debt As of March 31, 2026, the Company had $4.4 billion in total debt outstanding, which consisted of notes and debentures of APA and Apache and finance lease obligations. As of March 31, 2026, current debt included $2 million of finance lease obligations and $132 million of APA and Apache notes coming due within the next year.
Previous wording
•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 wording
On January 10, 2025, APA settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. In settling these offers pursuant to their respective terms, APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. The Company recognized a gain of $135 million on these purchases, including broker fees and loan costs.
Previous wording
Indenture Debt Activity During the first nine months of 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $122 million for an aggregate purchase price of $112 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $13 million. The Company recognized a $12 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025.
Current wording
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.
Previous wording
Unsecured 2025 Committed Credit Facilities On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:
Current wording
Committed Credit Facilities On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:
Showing the first 40 of 49 pairs. Open the source sections for the rest.
Rearranged previous paragraphs (2)
Previous report — wording carried 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).
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.