APA Corp
For the period ended Dec 31, 2024. Filed Feb 28, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 28, 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-K
Period ended 2023-12-31; filed 2024-02-22.
0001784031-24-000003
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-28.
0002040266-25-000007
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF 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 215 previous paragraphs and 242 current paragraphs.
86 unchanged; 85 reworded; 60 added; 42 removed; 2 previous and 11 current paragraphs rearranged.
Tables are not compared: 13 previous and 13 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (60)
Current report
•The Company pays a quarterly dividend of $0.25 per share on its common stock.
Current report
During 2024, the Company reported net income attributable to common stock of $804 million, or $2.27 per diluted share, compared to net income of $2.9 billion, or $9.25 per diluted share, in 2023. Net income in 2024 was primarily impacted by impairments of $1.1 billion, which included oil and gas property impairments of $796 million in the North Sea and $315 million in the U.S., and lower realized crude oil and natural gas prices during the year compared to 2023. The Company also recorded higher oil and gas revenues and associated operating expenses resulting from the Callon acquisition.
Current report
•During the first quarter of 2024, the Company completed a three-well exploration program in Alaska, confirming a working petroleum system on the Company’s acreage. The Company is currently drilling an additional exploration well on this acreage. The Company holds a 50 percent ownership interest in the project.
Current report
•During the fourth quarter of 2024, the Company entered into a new gas sales agreement which could result in improved pricing if certain production thresholds are met. The new gas sales agreement creates the potential for significant new drilling inventory with returns on par with oil.
Current 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.
Current report
•Sale of Non-core Permian Basin Properties On December 31, 2024, APA completed the sale of non-core producing properties in the Permian Basin that had a carrying value of $1.1 billion and associated asset retirement obligation of $224 million for total cash proceeds of $869 million after closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf.
Current report
•Non-core Acreage Divestiture During 2024, the Company completed the sale of non-core acreage in the East Texas Austin Chalk and Eagle Ford plays that had a carrying value of $347 million for aggregate cash proceeds of $255 million and the assumption of asset retirement obligations of $42 million.
Current report
•Mineral Rights Divestiture During 2024, the Company also completed the sale of non-core mineral and royalty interests in the Permian Basin that had a carrying value of $71 million for approximately $394 million subject to post-closing adjustments.
Current report
The Company’s worldwide NGL production increased 11 Mb/d compared to 2023, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, partially offset by natural production decline in the U.S., curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S.
Current report
GPT costs increased $98 million compared to 2023, primarily the result of increased oil and NGL production volumes in the U.S., primarily associated with the Callon acquisition, as well as increased charges for transporting gas production.
Current report
Taxes other than income increased $63 million compared to 2023, primarily from higher severance taxes driven by increased U.S. production volumes primarily attributable to the Callon acquisition.
Current report
Exploration expenses increased $118 million compared to 2023, primarily the result of dry hole expense associated with an exploration well in Suriname and the completion of an initial drilling campaign in Alaska, where two wells were unable to reach target objectives in the allotted seasonal time window.
Current report
TRS costs increased $153 million compared to 2023, primarily a result of transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in 2024 primarily comprised $147 million associated with the Callon acquisition, including $76 million of separation costs and $71 million of transaction and integration costs.
Current report
Net financing costs during 2024 increased $55 million compared to 2023, primarily driven by higher interest expense from higher average long-term debt balances.
Current report
Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be “more likely than not.” The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized.
Current report
In 2025, the Company plans to invest $2.5 billion to $2.6 billion in upstream capital investment. The Company is planning an 8-rig program in the Permian Basin, with approximately four rigs in each of the Midland and Delaware basins, and a 12-rig program in Egypt, with one rig dedicated to gas appraisal and exploration. This activity set translates to a combined development capital budget for the Permian Basin and Egypt of $2.2 billion to $2.3 billion. In addition, the Company will invest approximately $200 million for Suriname development and $100 million for exploration, primarily in Alaska.
Current report
Net cash provided by operating activities for the year ended December 31, 2024 totaled $3.6 billion, up $491 million from the year ended December 31, 2023, primarily due to higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices.
Current report
Proceeds from Term Loan Facility On April 1, 2024, the Company borrowed an aggregate $1.5 billion under a syndicated credit agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the closing of the Callon acquisition. For additional details of the credit agreement, see “Unsecured Committed Term Loan Facility”in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Current report
Payments on Term Loan Facility During 2024, the Company made payments of $600 million on its syndicated term loan credit agreement. For additional details of the credit agreement, see “Unsecured Committed Term Loan Facility”in the Liquidity section below. As of December 31, 2024, $900 million remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.
Current report
Payments on Callon Credit Agreement Upon closing of the Callon acquisition, the Company financed Callon’s repayment in full of its $472 million outstanding under the Callon Credit Agreement.
Current report
Payments on Fixed-Rate Debt In April and May 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 of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.
Current report
As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.
Current 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 only once upon the date of the closings under the Merger Agreement and 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). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first is less than $1.0 billion.
Current report
On April 1, 2024 (the Closing Date), APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027 and to allow the lender commitments for the 364-Day Tranche Loans to expire. As of December 31, 2024, there were $900 million in 3-Year Tranche Loans remaining outstanding under the Term Loan Credit Agreement.
Current report
Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA’s acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement.
Current report
Subsequent Event—Unsecured 2025 Committed Bank Credit Facilities
Current report
On January 15, 2025, the Company terminated commitments under the 2022 Agreements and in replacement thereof, entered into two unsecured syndicated credit agreements for general corporate purposes on terms substantially the same as those of the 2022 Agreements:
Current report
Letters of credit are available under each 2025 Agreement for credit support needs of APA and its subsidiaries, including in respect of North Sea decommissioning obligations. As of January 15, 2025, letters of credit aggregating approximately £253 million originally issued under the 2022 GBP Agreement were deemed issued and outstanding under the 2025 GBP Agreement.
Current report
Subsequent Event—APA Exchange and Tender Offers for Apache Indenture Debt
Current report
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.
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 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).
Current report
These offerings were not registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon an exemption therefrom, and the APA notes and debentures issued pursuant to such offers are subject to certain transfer restrictions. Each Registration Rights Agreement requires APA and Apache to use their commercially reasonable efforts to (i) cause to be filed a registration statement with respect to a registered offer to exchange each series of APA notes issued in settlement of the exchange and tender offers or new notes offering, as applicable, for registered notes issued by APA and guaranteed, if applicable, by Apache containing terms substantially identical in all material respects to the applicable series of APA notes issued in settlement of the exchange and tender offers or new notes offering (except that the registered notes will not contain terms with respect to transfer restrictions or any increase in annual interest rate) and (ii) cause such registration statement to become effective under the Securities Act. If, among other events, such exchange offers are not completed on or prior to the 360th day following January 10, 2025, then additional interest will accrue on the principal amount of such registrable securities at a rate of 0.25% per annum for the first 90-day period beginning on the day immediately following such registration default (which rate will be increased by an additional 0.25% per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may in no event exceed 1.00% per annum). To the extent Apache’s guarantee of the registrable securities is terminated in accordance with the terms of such guarantee, the registered notes will not be guaranteed by Apache, the exchange offer and registration requirements with respect thereto will be the sole obligation of the Company, and Apache will automatically be released from all obligations under the applicable Registration Rights Agreement.
Current report
The following table presents the aggregate principal amounts of notes and debentures outstanding under indentures of APA and Apache on January 10, 2025 upon settlement of the APA’s exchange and tender offers and new notes offering (Apache notes due 2025 were not included in APA’s exchange or tender offers):
Current report
(1)The Apache March 2026 notes, the Apache April 2026 notes, the Apache 2037 notes, the Apache 2040 notes, the Apache 2042 notes, the Apache 2047 debentures, and the Apache 2096 debentures were issued under the Senior Indenture, dated as of February 15, 1996, between Apache and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A., as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee), as trustee (an Apache Indenture).
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Removed paragraphs (42)
Previous report
On March 1, 2021, Apache Corporation consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.
Previous report
•The Company’s quarterly dividend was increased in the third quarter of 2022 from $0.125 per share to $0.25 per share, representing a return to pre-COVID-19 dividend levels.
Previous report
During 2023, the Company reported net income attributable to common stock of $2.9 billion, or $9.25 per diluted share, compared to net income of $3.7 billion, or $11.02 per diluted share, in 2022. Net income in 2023 was primarily impacted by lower revenues attributable to significantly lower realized commodity prices compared to 2022. The lower revenues were partially offset by a release of a majority of the Company’s U.S. tax valuation allowance, resulting in a non-cash deferred income tax benefit of approximately $1.7 billion during the fourth quarter of 2023. Net income in 2022 also benefited from approximately $1.2 billion of gains from the divestiture of certain non-core mineral rights in the Delaware Basin and completion of the BCP Business Combination.
Previous report
•During the fourth quarter of 2023, the Company commenced an exploration program in Alaska, where it anticipates drilling three exploration wells in the first half of 2024.
Previous report
•During 2023, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58, offshore Suriname. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an oil production capacity of 200,000 b/d. Detailed engineering studies are underway, and a final investment decision is expected by year-end 2024, with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.
Previous report
•During 2023, the Company signed a production sharing contract for Block 6 offshore Uruguay covering approximately four million net undeveloped acres and expects to commence exploration activities in 2024. In February 2024, the Company also signed a production sharing contract for Block 4 offshore Uruguay.
Previous report
In this all-stock transaction, each eligible outstanding share of Callon common stock will be exchanged for 1.0425 shares of APA common stock, representing an implied value to each Callon share of $38.31 per share based on the closing price of APA common stock on January 3, 2024. After closing, existing APA shareholders are expected to own approximately 81 percent of the combined company, and existing Callon shareholders are expected to own approximately 19 percent of the combined company. APA expects to retire the existing debt at Callon and replace it with APA term loan facilities totaling $2.0 billion.
Previous report
The transaction has been unanimously approved by the boards of directors of both APA and Callon and is expected to close during the second quarter of 2024, subject to customary closing conditions, termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and approval of the transaction by shareholders of both APA and Callon. This transaction complements and enhances APA’s asset base in the Permian Basin and adds to APA’s inventory of high quality, short-cycle opportunities. In addition, Callon’s assets provide additional scale to APA’s operations across the Permian Basin.
Previous report
•BCP Business Combination On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik). The Company deconsolidated ALTM upon closing the transaction. The deconsolidation provides a number of benefits to APA shareholders, including simplification of the Company’s financial reporting and enhanced comparability with its upstream-only peers, while maintaining a noncontrolling interest in future growth opportunities of Kinetik.
Previous report
•Delaware Basin Acquisition In the third quarter of 2022, the Company closed on the acquisition of oil and gas assets surrounding core acreage in the Delaware Basin for approximately $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during 2023.
Previous report
(5)Production volumes per day in the Company’s Alpine High field were as follows:
Previous report
The Company’s worldwide NGL production increased slightly compared to 2022, primarily a result of increased drilling activity and recompletions and less maintenance downtime in the North Sea, offset by natural production decline across all assets.
Previous report
GPT costs decreased $33 million compared to 2022, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $46 million from 2022, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the Company’s deconsolidation of Altus in February 2022, these midstream services continue to be provided by Kinetik but are no longer eliminated.
Previous report
Taxes other than income decreased $61 million compared to 2022, primarily from lower severance taxes driven by lower commodity prices and lower ad valorem tax rates.
Previous report
Exploration expenses decreased $110 million compared to 2022, primarily the result of higher dry hole expense in Suriname during 2022 coupled with lower exploration overhead and other activities in 2023.
Previous report
TRS costs decreased $11 million compared to 2022. Higher TRS costs in 2022 were incurred in connection with the BCP Business Combination in the first quarter of 2022.
Previous report
Net financing costs during 2023 decreased $67 million compared to 2022, primarily driven by losses incurred on the extinguishment of debt during 2022 and gains on extinguishment of debt during 2023, partially offset by an increase in interest expense during 2023 related to higher variable interest rates on credit facility borrowings.
Previous report
In 2024, the Company plans to invest $1.9 to $2.0 billion in upstream capital investment. This investment level reflects the Company’s strategy of moderating activity levels during periods of lower commodity prices. APA will invest for the long term by directing $100 million of the 2024 upstream budget toward exploration activities predominantly in Alaska and $50 million toward progressing a large-scale floating production storage and offloading (FPSO) project in Suriname. The Company’s worldwide adjusted oil and natural gas production is expected be relatively flat year over year, while NGL volumes are anticipated to be lower as the current strip prices would lead to ethane rejection in the U.S. for most of the year.
Previous report
Net cash provided by operating activities for the year ended December 31, 2023 totaled $3.1 billion, down $1.8 billion from the year ended December 31, 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items.
Previous report
Acquisition of Delaware Basin Properties During 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during 2023. Cash consideration paid during 2022 totaled $591 million.
Previous report
During 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
Previous report
On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed in part by Apache’s borrowing under the Company’s U.S. dollar-denominated revolving credit facility.
Previous report
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
Previous report
In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a 2022 Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a 2022 Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each 2022 Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
Previous report
As of December 31, 2023, the Company had not issued any CP Notes.
Previous report
Committed Delayed-Draw Term Loan Facility. On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders have committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Credit Agreement). Subject to satisfaction of certain limited conditions, APA may borrow under the Credit Agreement to refinance certain indebtedness of Callon Petroleum Company, a Delaware corporation (Callon), upon or after closing of APA’s pending acquisition of Callon pursuant to the previously announced Agreement and Plan of Merger among APA, Astro Comet Merger Sub Corp., a Delaware corporation and wholly owned subsidiary of APA, and Callon, dated January 3, 2024 (Merger Agreement).
Previous report
Two tranches of term loans would be available to APA for borrowing only on the date of closing of transactions under the Merger Agreement and satisfaction of certain other conditions under the Credit Agreement (Closing Date); of the aggregate $2.0 billion in commitments, $1.5 billion is for term loans that would mature three years after the Closing Date (3-Year Tranche Loans) and $500 million is for term loans that would mature 364 days after the Closing Date (364-Day Tranche Loans).
Previous report
Indebtedness of Callon that APA could refinance by borrowing under the Credit Agreement on the Closing Date includes 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, and together with the Callon Credit Agreement, Callon’s 2026 Notes, and Callon’s 2028 Notes, the Callon Indebtedness).
Previous report
The Credit Agreement has limited conditions to funding on the Closing Date loans requested by APA in accordance with the Credit Agreement, such as consummation of the transactions under the Merger Agreement, no Company Material Adverse Effect (as defined in the Merger Agreement) has occurred, repayment of all indebtedness outstanding under the Callon Credit Agreement and Callon’s 2026 Notes, and Callon having no other material indebtedness for borrowed money except for Callon’s 2028 Notes and Callon’s 2030 Notes or as permitted under the Credit Agreement or the Merger Agreement.
Previous report
Proceeds of loans made under the Credit Agreement may only be used to refinance the Callon Indebtedness and repay fees and expenses related to transactions under the Credit Agreement and the Merger Agreement. To the extent that borrowings by APA under the Credit Agreement are not so used on or before the date that is 120 days after the Closing Date, APA then must prepay the amount of such unused borrowings.
Previous report
If $400 million or more in aggregate principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes remains outstanding on the date which is 120 days after the Closing Date, Callon then must guarantee APA’s obligations under the Credit Agreement effective until the aggregate outstanding principal amount of Callon’s 2028 Notes and Callon’s 2030 Notes first is less than $400 million.
Previous report
APA may at any time prepay loans under the Credit Agreement. APA may at any time terminate, or from time to time reduce, the lenders’ commitments under the Credit Agreement. Unless previously terminated, the lenders’ commitments automatically terminate on the first to occur of: (i) the Closing Date, after giving effect to funding of each lender’s commitments on the Closing Date, (ii) APA’s acquisition of Callon pursuant to the Merger Agreement without loans being made under the Credit Agreement, (iii) termination of the Merger Agreement in accordance with its terms, and (iv) the Termination Date (as defined in, and may be extended pursuant to, the Merger Agreement).
Previous report
All borrowings under the Credit Agreement would be in U.S. Dollars and bear interest at one of the following two rate options, as selected by APA, plus the indicated margin:
Previous report
•One option is a base rate per annum equal to the greatest of (i) the applicable prime rate, (ii) the greater of the applicable federal funds rate and overnight bank funding rate, plus 0.50%, and (iii) an adjusted secured overnight financing rate published by the Federal Reserve Bank of New York (SOFR) for a one-month interest period plus 1.0%. The margin for this rate option (Term Base Rate Margin) is a rate per annum varying from 0.25% to 1.0% for 364-Day Tranche Loans, 0.375% to 1.125% for 3-Year Tranche Loans until the second anniversary of the Closing Date, and 0.625% to 1.375% for 3-Year Tranche Loans after the second anniversary of the Closing Date, in each case, based on the rating for senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache. Apache’s Long-Term Debt Rating currently applies.
Previous report
The Credit Agreement provides for a ticking fee payable by APA at a rate of 0.225% per annum on the daily average undrawn aggregate commitments thereunder; the ticking fee accrues during the period beginning on the date that is 90 days after January 3, 2024 to the earlier of (i) termination or expiration of the commitments or (ii) the Closing Date.
Previous report
As of December 31, 2023, Apache has incurred $819 million in decommissioning costs related to Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs. As of December 31, 2023, $293 million has been reimbursed from Trust A and $336 million has been reimbursed from the Letters of Credit. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
Previous report
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to use its available cash to fund the deficit.
Previous report
As of December 31, 2023, the Company has also recorded a $199 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $21 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $178 million is reflected under “Other current assets.”
Previous report
The Company recognized $212 million, $157 million, and $446 million during 2023, 2022, and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations.
Previous report
Apache also has an insurance policy with U.S. International Development Finance Corporation (DFC), which, subject to policy terms and conditions, provides up to $150 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting its share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $60 million in reinsurance to DFC.
Showing the first 40 of 42 passages. Open the source sections for the rest.
Reworded paragraphs (85)
Previous wording
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 (filed with the SEC on February 23, 2023).
Current wording
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of APA Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (filed with the SEC on February 22, 2024).
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. Prior to the BCP Business Combination (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).
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 inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to 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, including the impact of ongoing international conflicts, inflation, trade disputes, and actions taken by foreign oil and gas producing nations, including OPEC+, impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders; and (3) to responsibly manage its cost structure regardless of the oil price environment.
Previous wording
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For example, the Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices but accelerated the completion of eight Permian Basin oil producing wells. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. Capital investment plans were then aligned across other areas of the portfolio while maintaining a focus on the Company’s capital returns framework established in 2021.
Current wording
The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA’s diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For example, the Company curtailed production in the Permian Basin in the second half of 2024 in response to weakness in Waha natural gas and NGL prices; however, in Egypt, the Company contracted an additional drilling rig in late 2024 after signing an agreement to incentivize gas exploration and production at new pricing. In 2023, the Company decided to suspend drilling activity in the North Sea, as increasing cost and tax burdens impacted the competitiveness of these assets within the Company’s portfolio. Capital investment plans have accordingly been aligned across other areas of the portfolio while maintaining a focus on the Company’s capital returns framework.
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 2023, the Company has repurchased 76.1 million shares of the Company’s common stock. Subsequent to year-end 2023 and through the date of this filing on February 22, 2024, the Company repurchased 3.0 million shares, and as of February 22, 2024, the Company had remaining authorization to repurchase up to 40.9 million shares under the Company’s share repurchase programs.
Current wording
•Beginning in the fourth quarter of 2021 and through the end of 2024, the Company has repurchased 85.3 million shares of the Company’s common stock. Subsequent to year-end 2024 and through the date of this filing on February 28, 2025, the Company repurchased 3.9 million shares, and as of February 28, 2025, the Company had remaining authorization to repurchase up to 30.9 million shares under the Company’s share repurchase programs.
Previous wording
The Company generated $3.1 billion of cash from operating activities in 2023, which was $1.8 billion or 37 percent lower than 2022. APA’s lower operating cash flows for 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 8.7 million shares of its common stock for $329 million and paid $308 million in dividends to APA common stockholders during 2023.
Current wording
The Company generated $3.6 billion of cash from operating activities in 2024, which was $491 million or 16 percent higher than 2023. APA’s higher operating cash flows for 2024 were primarily driven by higher oil and gas revenues resulting from increased drilling activity in the Permian Basin and production from the acquired Callon properties, partially offset by lower realized commodity prices. The Company repurchased 9.2 million shares of its common stock for $246 million and paid $353 million in dividends to APA common stockholders during 2024.
Previous wording
•Daily boe production from the Company’s U.S. assets, which increased 2 percent from 2022, accounted for 54 percent of the Company’s worldwide production during 2023. The Company averaged five drilling rigs in the U.S. during the year, including three rigs in the Southern Midland Basin and two rigs in the Delaware Basin, and drilled and brought online 82 operated wells in 2023. The Company’s drilling was primarily focused on oil prospects, increasing oil production by approximately 12 percent in the U.S. compared to the prior year. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.
Current wording
•Daily boe production from the Company’s U.S. assets, which increased 30 percent from 2023, accounted for 62 percent of the Company’s worldwide production during 2024. The Company averaged nine drilling rigs in the U.S. during the year, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin, and drilled and brought online 159 operated wells in 2024. The Company’s drilling was primarily focused on oil prospects, and combined with the Callon acquisition, oil production increased approximately 63 percent in the U.S. compared to the prior year. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.
Previous wording
•In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 17 drilling rigs and drilled 91 new productive wells during 2023. During 2023, gross and net production from the Company’s Egypt assets decreased 2 percent and 1 percent, respectively, from 2022. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage opportunities provided by the 2021 merged concession agreement.
Current wording
•In Egypt, the Company continued its drilling and workover activity with a focus on oil prospects. The Company averaged 14 drilling rigs and drilled 62 new productive wells during 2024. During the same period, the Company averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. The 2024 gross and net production from the Company’s Egypt assets decreased 6 percent and 4 percent, respectively, from 2023.
Previous wording
•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program in the North Sea is now directed toward safety, base production management, and asset maintenance and integrity.
Current wording
•During the second quarter of 2023, the Company suspended all new drilling activity in the North Sea. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company’s investment program in the North Sea is now directed toward asset safety and integrity.
Previous wording
For a more detailed discussion related to the Company’s various geographic segments, refer to “Upstream Exploration and Production Properties—Operating Areas” set forth in Part I, Item 1 and 2 of this Annual Report on Form 10-K.
Current wording
For a more detailed discussion related to the Company’s various geographic segments, refer to “Exploration and Production—Operating Areas” set forth in Part I, Items 1 and 2 of this Annual Report on Form 10-K.
Previous wording
•Callon Petroleum Company Pending Acquisition On January 3, 2024, APA and Callon Petroleum Company (Callon) entered into a definitive agreement (Merger Agreement), pursuant to which APA will acquire Callon in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s net debt.
Current wording
•Callon Petroleum Company Acquisition On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt (the Callon acquisition). The acquired assets 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 wording
•Sales of Kinetik Shares Subsequent sales of Kinetik Shares have reduced APA’s ownership in Kinetik to approximately 9 percent as of December 31, 2023. During 2023, the Company sold a portion of its Kinetik Shares for cash proceeds of $228 million. During 2022, the Company sold a portion of its Kinetik Shares for $224 million.
Current wording
•Sales of Kinetik Shares During 2022 and 2023, the Company sold a portion of its Kinetik Shares for cash proceeds of $224 million and $228 million, respectively. During the first quarter of 2024, the Company sold its remaining shares of Kinetik Class A Common Stock for cash proceeds of $428 million. On April 3, 2024, the Company’s designated director resigned from the Kinetik Holdings, Inc. (Kinetik) board of directors.
Previous wording
(2)Average sales volumes from the North Sea were 45,476 boe/d, 40,812 boe/d, and 44,179 boe/d for 2023,2022, and 2021, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Current wording
(2)Average sales volumes from the North Sea were 33,954 boe/d, 45,476 boe/d, and 40,812 boe/d for 2024,2023, and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
Previous wording
Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2023 were down 19 percent compared to 2022, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2023 averaged $80.72 per barrel.
Current wording
Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2024 were down 3 percent compared to 2023, a direct result of decreasing benchmark oil prices over the past year. Crude oil prices realized in 2024 averaged $78.08 per barrel.
Previous wording
•The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $1.80 per Mcf in 2023, a 66 percent decrease from an average of $5.31 per Mcf in 2022.
Current wording
•The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $0.71 per Mcf in 2024, a 61 percent decrease from an average of $1.80 per Mcf in 2023.
Previous wording
•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.91 per Mcf in 2023, a 2 percent increase from an average of $2.85 per Mcf in 2022.
Current wording
•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.94 per Mcf in 2024, a one percent increase from an average of $2.91 per Mcf in 2023. In the fourth quarter of 2024, the Company entered into a new gas sales agreement, which could result in improved pricing if certain production thresholds are met. The new gas sales agreement, which is effective beginning January 2025, creates the potential for significant new drilling inventory with returns on par with oil.
Previous wording
•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $13.02 per Mcf in 2023, a 44 percent decrease from an average of $23.36 per Mcf in 2022.
Current wording
•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $10.84 per Mcf in 2024, a 17 percent decrease from an average of $13.02 per Mcf in 2023.
Previous wording
Crude oil revenues for 2023 totaled $6.0 billion, an $838 million decrease from the 2022 total of $6.8 billion. A 19 percent decrease in average realized prices reduced 2023 revenues by $1.3 billion compared to 2022, while 8 percent higher average daily production increased revenues by $430 million. Average daily production in 2023 was 203 Mb/d, with prices averaging $80.72 per barrel. Crude oil sales accounted for 81 percent of the Company’s 2023 oil and gas production revenues and 50 percent of its worldwide production.
Current wording
Crude oil revenues for 2024 totaled $7.0 billion, a $969 million increase from the 2023 total of $6.0 billion. A 20 percent higher average daily production increased 2024 revenues by $1.2 billion compared to 2023, while a 3 percent decrease in average realized prices reduced revenues by $196 million. Average daily production in 2024 was 244 Mb/d, with prices averaging $78.08 per barrel. Crude oil sales accounted for 85 percent of the Company’s 2024 oil and gas production revenues and 54 percent of its worldwide production.
Previous wording
The Company’s worldwide crude oil production increased 15 Mb/d compared to 2022, primarily a result of increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.
Current wording
The Company’s worldwide crude oil production increased 41 Mb/d compared to 2023, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were partially offset by natural production decline across all assets, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.
Previous wording
Natural gas revenues for 2023 totaled $880 million, a $689 million decrease from the 2022 total of $1.6 billion. A 42 percent decrease in average realized prices reduced 2023 revenues by $652 million compared to 2022, while 4 percent lower average daily production decreased revenues by $37 million. Average daily production in 2023 was 828 MMcf/d, with prices averaging $2.91 per Mcf. Natural gas sales accounted for 12 percent of the Company’s 2023 oil and gas production revenues and 34 percent of its worldwide production.
Current wording
Natural gas revenues for 2024 totaled $584 million, a $296 million decrease from the 2023 total of $880 million. A 32 percent decrease in average realized prices reduced 2024 revenues by $285 million compared to 2023, while 2 percent lower average daily production decreased revenues by $11 million. Average daily production in 2024 was 814 MMcf/d, with prices averaging $1.97 per Mcf. Natural gas sales accounted for 7 percent of the Company’s 2024 oil and gas production revenues and 30 percent of its worldwide production.
Previous wording
The Company’s worldwide natural gas production decreased 37 MMcf/d compared to 2022, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., partially offset by increased drilling activity and recompletions and less maintenance downtime in the North Sea.
Current wording
The Company’s worldwide natural gas production decreased 14 MMcf/d compared to 2023, primarily a result of natural production decline in the North Sea and U.S., reduced gas-focused activity in Egypt, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.
Previous wording
NGL revenues for 2023 totaled $508 million, a $308 million decrease from the 2022 total of $816 million. A 38 percent decrease in average realized prices primarily drove the decrease in NGL revenues compared to 2022. Average daily production in 2023 was 64 Mb/d, with prices averaging $21.54 per barrel. NGL sales accounted for 7 percent of the Company’s 2023 oil and gas production revenues and 16 percent of its worldwide production.
Current wording
NGL revenues for 2024 totaled $646 million, a $138 million increase from the 2023 total of $508 million. A 17 percent higher average daily production increased 2024 revenues by $95 million compared to 2023, while an 8 percent increase in average realized prices increased 2024 revenues by $43 million. Average daily production in 2024 was 75 Mb/d, with prices averaging $23.37 per barrel. NGL sales accounted for 8 percent of the Company’s 2024 oil and gas production revenues and 16 percent of its worldwide production.
Previous wording
Purchased oil and gas sales represent volumes primarily attributable to domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations and delivery commitments. In 2023, in order to diversify the pricing received for the sale of its natural gas, the Company sold a portion of its purchased gas at international gas prices. Sales related to purchased volumes decreased $961 million for the year ended December 31, 2023 to $894 million from $1.9 billion in 2022. Purchased oil and gas sales were partially offset by associated purchase costs of $742 million and $1.8 billion for the years ended December 31, 2023 and 2022, respectively. The decrease in purchased oil and gas sales is primarily a result of lower average domestic natural gas prices during 2023 compared to 2022.
Current wording
Purchased oil and gas sales represent volumes primarily attributable to domestic gas purchases that were sold by the Company to fulfill natural gas takeaway obligations and delivery commitments. Sales related to purchased volumes increased $647 million for the year ended December 31, 2024 to $1.5 billion from $894 million in 2023. Purchased oil and gas sales were partially offset by associated purchase costs of $1.0 billion and $742 million for the years ended December 31, 2024 and 2023, respectively. The increase in purchased oil and gas sales was primarily driven by increased oil volume sales coupled with activity associated with the Callon acquisition.
Previous wording
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2023, 2022, and 2021. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.
Current wording
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2024, 2023, and 2022. All operating expenses include costs attributable to a noncontrolling interest in Egypt.
Previous wording
LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 50 percent of the Company’s total 2023 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
Current wording
LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 54 percent of the Company’s total 2024 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
Previous wording
During 2023, LOE decreased $8 million, or 1 percent, compared to 2022. On a per-boe basis, LOE decreased $0.27, or 3 percent, compared to 2022, from $9.95 per boe to $9.68 per boe. The decrease in costs was driven by lower average foreign currency exchange impacts against the U.S. dollar and decreased workover activity primarily in the North Sea. These decreases were mostly offset by higher labor costs and other operating costs trending with general inflation across all regions.
Current wording
During 2024, LOE increased $254 million, or 18 percent, compared to 2023. On a per-boe basis, LOE increased $0.48, or 5 percent, compared to 2023, from $9.68 per boe to $10.16 per boe. The increase in absolute costs was primarily driven by higher operating and labor costs and workover activity associated with the Callon acquisition. The Company also had higher labor costs and other operating costs trending with general inflation across all regions, which were partially offset by changes in foreign currency exchange rates against the U.S. dollar.
Previous wording
Purchased oil and gas costs decreased $1.0 billion for the year ended December 31, 2023, to $742 million from $1.8 billion in 2022. The decrease is a result of lower average domestic natural gas prices during 2023 compared to the prior year. Purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $894 million for the year ended 2023, as discussed above.
Current wording
Purchased oil and gas costs increased $305 million for the year ended December 31, 2024, to $1.0 billion from $742 million in 2023. The increase is primarily driven by increased oil volume purchases coupled with activity associated with the Callon acquisition during 2024, partially offset by lower average natural gas prices during 2024 compared to the prior-year period. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill natural gas takeaway obligations and delivery commitments totaling $1.5 billion for the year ended 2024, as discussed above.
Previous wording
G&A expenses decreased $132 million compared to 2022, primarily driven by lower cash-based stock compensation expense during 2023 resulting from decreases in the Company’s stock price and in the achievement of performance and financial objectives as defined in the stock award plans. For additional information refer to Note 14—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Current wording
G&A expenses increased $21 million compared to 2023, primarily driven by higher overall labor costs across the Company and the Callon acquisition, partially offset by lower cash-based stock compensation expense resulting from changes in the Company’s stock price in 2024. For additional information refer to Note 13—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Previous wording
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2023 increased $314 million compared to 2022. The Company’s oil and gas property DD&A rate increased $1.94 per boe in 2023 compared to 2022, from $8.18 per boe to $10.12 per boe, driven by general cost inflation and the unit of production impact of lower proved reserves during 2023. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and acquisitions in the U.S.
Current wording
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2024 increased $735 million compared to 2023. The Company’s oil and gas property DD&A rate increased $3.32 per boe in 2024 compared to 2023, from $10.12 per boe to $13.44 per boe, driven by negative gas price-related reserve revisions in the U.S. Permian Basin and impacts resulting from the Callon acquisition in 2024. The increase on an absolute basis was also driven by higher capital expenditures incurred in the U.S. and the Callon acquisition.
Previous wording
During 2023, the Company recorded $61 million of impairments, primarily in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea. No asset impairments were recorded in 2022.
Current wording
During 2024, the Company recorded $1.1 billion of impairments, which included $796 million of oil and gas property impairments in the North Sea, a $315 million impairment of certain oil and gas properties in the U.S. to agreed-upon proceeds for their disposition, and $18 million of inventory impairments in the North Sea and U.S. During 2023, the Company recorded $61 million of impairments, primarily in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.
Previous wording
Income tax expense decreased $2.0 billion from $1.7 billion during 2022 to an income tax benefit of $324 million during 2023. The Company’s 2023 effective income tax rate was primarily impacted by a deferred tax expense related to the release of a portion of its valuation allowance against U.S. deferred tax assets and the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023. During 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
Current wording
Income tax expense increased $741 million from an income tax benefit of $324 million during 2023 to an income tax expense of $417 million during 2024. The Company’s 2024 effective income tax rate was primarily impacted by taxes related to foreign operations. During 2023, the Company’s effective income tax rate was primarily impacted by a deferred tax benefit related to the release of a portion of its valuation allowance against U.S. deferred tax assets and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023.
Previous wording
On July 14, 2022, the Energy Profits Levy was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under accounting principles generally accepted in the U.S., the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded a deferred tax expense of $208 million and $174 million related to the remeasurement of the U.K. deferred tax liability in 2022 and 2023, respectively.
Current wording
On July 14, 2022, the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy) was enacted, receiving Royal Assent. Under the law, an additional levy was assessed at a 25 percent rate, effective for the period of May 26, 2022 through December 31, 2025. The Finance Act 2023 included amendments to the Energy Profits Levy that increased the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. As a result, the Company recorded a deferred tax expense of $174 million and $208 million related to the remeasurement of the U.K. deferred tax liability in 2023 and 2022, respectively.
Previous wording
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 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 is not an applicable corporation in 2023 but will be subject to CAMT beginning on January 1, 2024. The Company is continuing to evaluate the provisions of the IRA and its effects on the Company’s consolidated financial statements.
Current wording
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. In 2024, the Company accrued tax expense of $74 million, which results in a tax credit that can be carried forward indefinitely to offset regular federal income tax expense in subsequent years.
Previous wording
In December 2021, the Organisation for Economic Co-operation and Development (OECD) released Model Rules under the Pillar Two framework, which imposes a 15 percent global minimum tax on large corporations. Such Model Rules have been adopted in certain jurisdictions in which the Company operates, including the United Kingdom, with an effective date of January 1, 2024. While the Company does not anticipate that Pillar Two will have a material impact on its effective tax rate, the Company will continue to evaluate the potential impacts of enacted and pending legislation in the jurisdictions in which it operates.
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
The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. The Company showed positive income over the three-year period ended December 31, 2023. During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion. The remaining U.S. valuation allowance relates primarily to foreign tax credit and capital loss carryforwards.
Current wording
During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion.
Previous wording
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. On September 26, 2022, the Company received a Statutory Notice of Deficiency from the IRS disallowing certain net operating loss carryback and research and development credit refund claims. As a result of the disallowance, on December 14, 2022, the Company filed a petition with the U.S. Tax Court challenging the tax adjustments and requesting a redetermination of the deficiencies stated in the notice. The Company is also under audit in various states and foreign jurisdictions as part of its normal course of business.
Current wording
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is under audit by the Internal Revenue Service and in various states and foreign jurisdictions as part of its normal course of business.
Previous wording
At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s current commitment to return capital to shareholders through a mix of dividends and share buybacks remains unchanged.
Current wording
Based on this development capital budget, the Company anticipates production in 2025 to be slightly higher compared to 2024. This investment profile underscores the progress the Company has made on capital efficiency through the integration of Callon and stabilization of Egypt volumes. At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s current commitment to return capital to shareholders through a mix of dividends and share buybacks remains unchanged.
Previous wording
For the year ended December 31, 2023, the Company recognized a slight downward reserve revision related to decreases in commodity prices during the year. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2023, 2022, and 2021, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Current wording
For the year ended December 31, 2024, the Company recognized downward reserve revisions related to decreases in commodity prices during the year. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2024, 2023, and 2022, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 17—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Previous wording
Proceeds from Asset Divestitures The Company received $29 million and $778 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2023 and 2022, respectively. For more information regarding the Company’s acquisitions and divestitures and equity method interests, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Current wording
Proceeds from Asset Divestitures The Company received $1.6 billion and $29 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2024 and 2023, respectively. For more information regarding the Company’s divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Showing the first 40 of 85 pairs. Open the source sections for the rest.
Rearranged current paragraphs (11)
Current report — wording carried from elsewhere
•One agreement was denominated in US dollars (the 2022 USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million was committed).
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.
Current report — wording carried from elsewhere
Margins are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2024, Apache’s Long-Term Debt Rating applied, and the Term Base Rate Margin was 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin was 1.75% for 3-Year Tranche Loans.
Current report — wording carried from elsewhere
APA is subject to representations and warranties, covenants, and events of default under the Term Loan Credit Agreement, such as:
Current report — wording carried from elsewhere
•Lenders may accelerate payment maturity and terminate lending commitments for nonpayment and other breaches; if APA or certain subsidiaries default on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of APA or certain subsidiaries.
Current report — wording carried from elsewhere
The Company was in compliance with the terms of the Term Loan Credit Agreement as of December 31, 2024.
Current report — wording carried from elsewhere
Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). APA’s Long-Term Debt Rating currently applies, and the Base Rate Margin is 0.30%, the Applicable Margin is 1.30%, and the facility fee is 0.20%.
Current report — wording carried from elsewhere
•A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65% at the end of any fiscal quarter.
Current report — wording carried from elsewhere
•A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada. Liens on assets also are permitted if debt secured thereby does not exceed 15% of APA’s consolidated net tangible assets.
Current report — wording carried from elsewhere
•Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.
Current report — wording carried from elsewhere
For information regarding pension or postretirement benefit obligations, refer to Note 12—Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
Currently, the Term Base Rate Margin is 0.625% for 364-Day Tranche Loans and 0.75% for 3-Year Tranche Loans, and the Term Applicable Margin is 1.625% for 364-Day Tranche Loans and 1.75% for 3-Year Tranche Loans.
Previous report — wording carried elsewhere
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.