0001841666-26-000015 | 10-K | XBRL Viewer

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INCOME TAXES - Schedule of Key Jurisdictions of Company's Earliest Open Tax Years (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Unrecognized Tax Benefits [Roll Forward]
Balance at beginning of year	$ 64	$ 89	$ 93	$ 89
Additions based on tax positions related to prior year	0	1	4
Reductions for tax positions of prior years	(25)	(5)	0
Balance at end of year	$ 64	$ 89	$ 93	$ 89

MAJOR CUSTOMERS (Details)	12 Months Ended
MAJOR CUSTOMERS (Details)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Customer Concentration Risk \| Oil and Gas Production Revenues \| Egyptian General Petroleum Corporation
Revenue, Major Customer [Line Items]
Concentration risk percentage	15.00%	17.00%	15.00%

- Definition

For an entity that discloses a concentration risk in relation to quantitative amount, which serves as the "benchmark" (or denominator) in the equation, this concept represents the concentration percentage derived from the division.

+ References + Details

INCOME TAXES - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Apr. 01, 2024
Income Tax [Line Items]
Accrued tax expense			$ 71.0
Current income tax provision		$ 739.0	1,153.0	$ 1,338.0
Deferred income tax benefit	$ 1,700.0	(384.0)	96.0	1,708.0
Net interest expense carryforward		607.0
Tax expense recorded for interest and penalties		8.2	2.0	2.0
Accrued for payment of interest and penalties	$ 7.0	0.0	$ 9.0	7.0
Internal Revenue Service (IRS)
Income Tax [Line Items]
Current income tax provision		72.0
One Big Beautiful Bill Act Of 2025
Income Tax [Line Items]
Current income tax provision		42.0
Foreign
Income Tax [Line Items]
Remeasurement of deferred tax liability		78.0		$ 174.0
Net operating losses		211.0
Tax credit carryforward, amount		1,935.0
U.S.
Income Tax [Line Items]
Net operating losses		9,463.0
Operating loss carryforwards subject to annual limitation		2,100.0
State
Income Tax [Line Items]
Net operating losses		$ 6,523.0
Callon Petroleum Company
Income Tax [Line Items]
Deferred tax asset					$ 565.0

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Non-cash Impairment Charges of Proved and Unproved Properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 18,000,000	$ 1,111,000,000	$ 0
Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	2,000,000	35,000,000	22,000,000
U.S. \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	315,000,000	0
U.S. \| Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	34,000,000	10,000,000
Egypt \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	18,000,000	0	0
Egypt \| Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	2,000,000	0	0
North Sea \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	796,000,000	0
North Sea \| Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	0	0	11,000,000
Other International \| Unproved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments	$ 0	$ 1,000,000	$ 1,000,000

RETIREMENT AND DEFERRED COMPENSATION PLANS - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Details)	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	100.00%	100.00%
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	61.00%	62.00%
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	3.00%	4.00%
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	36.00%	33.00%
Cash
Defined Benefit Plan Disclosure [Line Items]
Percentage of Plan Assets at Year-End	0.00%	1.00%

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST - USD ($) $ in Millions	Total	APA SHAREHOLDERS’ EQUITY	Common Stock	Paid-In Capital	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Income	Noncontrolling Interest
Beginning balance at Dec. 31, 2022	$ 1,345	$ 423	$ 262	$ 11,420	$ (5,814)	$ (5,459)	$ 14	$ 922
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	2,855	2,855			2,855
Net income attributable to noncontrolling interest	352							352
Distributions to noncontrolling interest	(238)							(238)
Common dividends ($1.00 per share)	(308)	(308)		(308)
Common stock activity, net	(13)	(13)	1	(14)
Treasury stock activity, net	(331)	(331)				(331)
Compensation expense	23	23		23
Other	6	6		5			1
Ending balance at Dec. 31, 2023	3,691	2,655	263	11,126	(2,959)	(5,790)	15	1,036
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	804	804			804
Net income attributable to noncontrolling interest	314							314
Distributions to noncontrolling interest	(268)							(268)
Common dividends ($1.00 per share)	(352)	(352)		(352)
Common stock activity, net	2,414	2,414	44	2,370
Treasury stock activity, net	(247)	(247)				(247)
Compensation expense	26	26		26
Other	(20)	(20)		(17)			(3)
Ending balance at Dec. 31, 2024	6,362	5,280	307	13,153	(2,155)	(6,037)	12	1,082
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to common stock	1,434	1,434			1,434
Net income attributable to noncontrolling interest	258							258
Distributions to noncontrolling interest	(430)							(430)
Common dividends ($1.00 per share)	(359)	(359)		(359)
Common stock activity, net	(5)	(5)	1	(6)
Treasury stock activity, net	(283)	(283)				(283)
Compensation expense	26	26		26
Other	0	0		2			(2)
Ending balance at Dec. 31, 2025	$ 7,003	$ 6,093	$ 308	$ 12,816	$ (721)	$ (6,320)	$ 10	$ 910

DEBT AND FINANCING COSTS - Schedule of Debt (Details) - USD ($)	Dec. 31, 2025	Aug. 20, 2025	Jun. 20, 2025	Jan. 10, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Long-term debt, gross	$ 4,511,000,000
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Long-term debt				Long-term debt
Apache finance lease obligations	$ 28,000,000				$ 30,000,000
Unamortized discount	(23,000,000)				(25,000,000)
Debt issuance costs	23,000,000				29,000,000
Total debt	4,493,000,000				6,044,000,000
Current maturities	(213,000,000)				(53,000,000)
Long-term debt	4,280,000,000				5,991,000,000
Commercial paper
Debt Instrument [Line Items]
Debt instrument, face amount	2,000,000,000.0		$ 1,800,000,000
Short-term debt	0				323,000,000
APA Notes and Debentures
Debt Instrument [Line Items]
Debt instrument, face amount	$ 3,600,000,000				932,000,000
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount				$ 850,000,000
4.625% notes due 2025 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.625%	4.625%
Debt instrument, face amount		$ 51,000,000
Long-term debt, gross	$ 0				51,000,000
7.70% notes due 2026 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	7.70%
Long-term debt, gross	$ 79,000,000				78,000,000
7.95% notes due 2026 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	7.95%
Long-term debt, gross	$ 132,000,000				132,000,000
4.875% notes due 2027 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.875%
Long-term debt, gross	$ 108,000,000				108,000,000
4.375% notes due 2028 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.375%
Long-term debt, gross	$ 315,000,000				325,000,000
7.75% notes due in 2029 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	7.75%
Long-term debt, gross	$ 232,000,000				235,000,000
4.250% notes due 2030 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 475,000,000				516,000,000
6.10% notes due 2035 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	6.10%			6.10%
Debt instrument, face amount				$ 350,000,000
Long-term debt, gross	$ 350,000,000				0
6.000% notes due 2037 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	6.00%
Long-term debt, gross	$ 433,000,000				443,000,000
5.100% notes due 2040 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	5.10%
Long-term debt, gross	$ 763,000,000				1,333,000,000
5.250% notes due 2043 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	5.25%
Long-term debt, gross	$ 244,000,000				399,000,000
4.750% notes due 2043 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.75%
Long-term debt, gross	$ 217,000,000				428,000,000
4.250% notes due 2044 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	4.25%
Long-term debt, gross	$ 100,000,000				211,000,000
7.375% notes due 2049 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	7.375%
Long-term debt, gross	$ 150,000,000				150,000,000
5.350% notes due 2049 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	5.35%
Long-term debt, gross	$ 374,000,000				387,000,000
6.75% notes due 2055 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	6.75%
Long-term debt, gross	$ 500,000,000				0
7.625% debentures due 2096 \| Unsecured Debt
Debt Instrument [Line Items]
Debt interest rate	7.625%
Long-term debt, gross	$ 39,000,000				39,000,000
Notes and debentures before unamortized discount and debt issuance costs \| Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, fair value	4,300,000,000				4,400,000,000
Long-term debt, gross	4,511,000,000				4,835,000,000
Term loan facility \| Line of Credit \| Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	0				900,000,000
Syndicated credit facilities \| Line of Credit \| Revolving Credit Facility
Debt Instrument [Line Items]
Syndicated credit facilities	$ 0				10,000,000
APA Notes and Debentures
Debt Instrument [Line Items]
Debt instrument, fair value					$ 0

DEBT AND FINANCING COSTS - APA Exchange and Tender Offers for Apache Indenture Debt (Details) - USD ($)	Jan. 10, 2025	Dec. 31, 2025	Sep. 18, 2025	May 31, 2025
Apache Corp \| Former Facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Guaranteed obligations, maximum				$ 1,000,000,000
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount	$ 850,000,000
Unsecured Debt \| 6.10% notes due 2035
Debt Instrument [Line Items]
Debt instrument, face amount	$ 350,000,000
Debt interest rate	6.10%	6.10%
Unsecured Debt \| 6.75% notes due 2055
Debt Instrument [Line Items]
Debt instrument, face amount	$ 500,000,000
Debt interest rate	6.75%
Unsecured Debt \| APA Corp
Debt Instrument [Line Items]
Debt instrument, face amount	$ 2,500,000,000
Repayments	2,500,000
Debt instrument repurchase program	869,000,000
Net of issuance costs	839,000,000
Unsecured Debt \| APA Corp \| Unregistered Notes
Debt Instrument [Line Items]
Debt instrument, face amount			$ 3,600,000,000
Unsecured Debt \| APA Corp \| Registered Notes And Debentures
Debt Instrument [Line Items]
Percentage Of debt exchanged			9900.00%
Unsecured Debt \| Apache Corp
Debt Instrument [Line Items]
Debt instrument, face amount	203,000,000
Debt repurchased principle amount	1,000,000,000
Discount (premium) to par of debt repurchase	$ 135,000,000

CAPITALIZED EXPLORATORY WELL COSTS

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2025, 2024, and 2023. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Capitalized well costs at beginning of year	$	237	$	586	$	474
Additions pending determination of proved reserves	234		240		265

Reclassifications to proved properties	(118)		(506)		(135)
Charged to exploration expense	(15)		(83)		(18)
Capitalized well costs at end of year	$	338	$	237	$	586

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:


	2025		2024		2023

	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	158	$	107	$	156
Exploratory well costs capitalized for a period greater than one year	180		130		430
Capitalized well costs at end of year	$	338	$	237	$	586

Number of projects with exploratory well costs capitalized for a period greater than one year	7		12		33

Projects with exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Exploratory well costs capitalized for a period greater than one year since completion of drilling were $180 million at December 31, 2025, with $121 million related to Suriname exploration and appraisal. Analysis of well results and appraisal activity is ongoing. The remaining projects pertain to onshore drilling activity in Egypt and Alaska, for which continued testing and evaluation is being performed.

Dry hole expenses from suspended exploratory well costs previously capitalized for greater than one year at December 31, 2024 totaled $8 million. These expenses pertained to projects in Egypt.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2025, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:


	Total		2024		2023		2022 and Prior

	(In millions)
Suriname	$	121	$	—	$	60	$	61
United States	48		48		—		—
Egypt	11		7		4		—

	$	180	$	55	$	64	$	61

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities and Locations on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Instruments and Hedges, Liabilities [Abstract]
Current Liabilities: Other current liabilities	$ 77	$ 0
Deferred Credits and Other Noncurrent Liabilities: Other	$ 0	$ 18
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Other current liabilities (Note 6)	Other current liabilities (Note 6)
Total derivative liabilities	$ 77	$ 18

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

+ References

Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
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+ Details

CAPITAL STOCK

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

CAPITAL STOCK

Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023
Balance, beginning of year	365,397,149	303,575,901	311,559,149
Shares issued for stock-based compensation plans:
Treasury shares issued	—	—	2,016
Common shares issued	458,481	70,983,745	725,914
Treasury shares acquired	(12,890,984)	(9,162,497)	(8,711,178)
Balance, end of year	352,964,646	365,397,149	303,575,901

Net Income per Common Share

The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2025, 2024, and 2023:


	2025					2024					2023
	Income		Shares	Per Share		Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:


Income attributable to common stock	$	1,434	359	$	3.99	$	804	353	$	2.28	$	2,855	308	$	9.26
Effect of Dilutive Securities:
Stock compensation awards	$	—	—	$	—	$	—	—	$	(0.01)	$	—	1	$	(0.01)
Diluted:


Income attributable to common stock	$	1,434	359	$	3.99	$	804	353	$	2.27	$	2,855	309	$	9.25

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 3.3 million, 2.0 million, and 1.9 million for the years ended December 31, 2025, 2024, and 2023, respectively.

Stock Repurchase Program

During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of 40 million shares of the Company’s common stock. During the third quarter of 2022, the Company's Board of Directors authorized the purchase of an additional 40 million shares of the Company's common stock.

During 2025, the Company repurchased 12.9 million shares at an average price of $21.73 per share, and as of December 31, 2025, the Company had remaining authorization to repurchase 21.9 million shares. During 2024, the Company repurchased 9.2 million shares at an average price of $26.83 per share. During 2023, the Company repurchased 8.7 million shares at an average price of $37.81 per share.

The Company is not obligated to acquire any additional shares. Shares may be purchased either in the open market or through privately held negotiated transactions.

Common Stock Dividend

For the years ended December 31, 2025, 2024, and 2023, the Company declared common stock dividends totaling $1.00 per share.

Stock Compensation Plans

The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans.

On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2025, 5.2 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.

Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	26	$	16	$	27
Exploration	7		4		7
General and administrative	74		29		50
Total stock-settled and cash-settled compensation expensed	107		49		84
Stock-settled and cash-settled compensation capitalized	15		9		13
Total stock-settled and cash-settled compensation costs	$	122	$	58	$	97

Stock Options

As of December 31, 2025, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan and the 2011 Omnibus Equity Compensation Plan (the 2011 Plan and, with the 2016 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.

During the year ended December 31, 2025, compensation costs related to stock options charged to expense and capitalized were $8 million and $1 million, respectively.

The following table summarizes stock option activity for the years ended December 31, 2025, 2024, and 2023:


	2025			2024			2023
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	1,416	$	48.64	1,465	$	48.48	2,078	$	57.71
Granted	1,722	23.26		—	—		—	—
Exercised	—	—		—	—		(12)	42.38
Forfeited	(224)	22.86		—	—		—	—
Expired	(139)	48.47		(49)	43.91		(601)	80.53
Outstanding, end of year(1)	2,775	34.98		1,416	48.64		1,465	48.48
Expected to vest	1,427	23.33		—	—		—	—
Exercisable, end of year(1)(2)	1,348	47.30		1,416	48.64		1,465	48.48

(1)As of December 31, 2025, options exercisable had a weighted average remaining contractual life of 1.5 years and $97 thousand aggregate intrinsic value and options outstanding had a weighted average remaining contractual life of 5.4 years and $2 million aggregate intrinsic value.

(2)As of December 31, 2025, there was $6 million of total unrecognized compensation cost related to 1,426,518 unvested stock options.

During the year ended December 31, 2025, there were 1,721,990 options issued and no options exercised. During the year ended December 31, 2024, there were no options issued or exercised. During the year ended December 31, 2023, there were no options issued and 12,183 options exercised.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of the Company’s common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.


	2025			2024	2023
Expected volatility	57.37		%	N/A	N/A
Expected dividend yields	4.30		%	N/A	N/A
Expected term (in years)	6			N/A	N/A
Risk-free rate	4.43		%	N/A	N/A
Weighted-average grant-date fair value	$	9.50		N/A	N/A

In January 2026, the Company issued 1,487,317 options to purchase shares of the Company’s common stock to eligible employees under the Omnibus Plans, at an average fair value of $9.75 per share. The total compensation cost of $15 million is estimated to be recognized over a three-year vesting period of these options.

Restricted Stock Units and Restricted Stock Phantom Units

The Company has restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.

For the years ended December 31, 2025, 2024, and 2023, compensation costs charged to expense for the restricted stock units and restricted stock phantom units were $46 million, $53 million, and $73 million, respectively. For the years ended December 31, 2025, 2024, and 2023, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $10 million, $9 million, and $11 million, respectively.

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2025, 2024, and 2023:


	2025			2024			2023
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,415	$	35.07	1,480	$	30.69	1,885	$	23.08
Granted	827	23.29		897	33.48		661	41.60
Assumed awards from Callon acquisition	—	—		1,498	35.43		—	—
Vested(3)	(797)	32.74		(2,295)	31.83		(975)	23.31
Forfeited	(282)	31.40		(165)	35.48		(69)	32.44
Expired	—	—		—	—		(22)	27.81
Non-vested, end of year(1)(2)	1,163	29.19		1,415	35.07		1,480	30.69

(1)As of December 31, 2025, there was $10 million of total unrecognized compensation cost related to 1,163,194 unvested stock-settled restricted stock units.

(2)As of December 31, 2025, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2025, 2024, and 2023 were $26 million, $73 million, and $23 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023

	(In thousands)
Non-vested, beginning of year	3,917	4,478	5,709

Granted(1)	2,302	2,369	1,972
Vested	(1,887)	(2,568)	(2,851)
Forfeited	(914)	(362)	(340)
Expired	—	—	(12)
Non-vested, end of year(2)	3,418	3,917	4,478

(1)Restricted stock phantom units granted during 2025, 2024, and 2023 included 2,301,540, 2,369,605, and 1,972,116 awards, respectively, based on the per-share market price of APA common stock.

(2)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2025 was approximately $38 million.

In January 2026, the Company awarded 624,467 restricted stock units and 2,115,116 restricted stock phantom units based on APA’s weighted-average per-share market price of $23.88 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $15 million and $51 million, respectively, and was calculated based on the per-share fair market value of a share of the Company’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement.

Performance Program

To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of cash-settled conditional restricted stock phantom units to eligible employees. APA has a performance program for certain eligible employees with payout for a portion of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining portion of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2025, are as described below:

•In January 2022, the Company’s Board of Directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units. A total of 713,514 phantom units were outstanding as of December 31, 2025. The results for the performance period yielded a payout of 118 percent of target.

•In January 2023, the Company’s Board of Directors approved the 2023 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 822,200 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 636,488 phantom units were outstanding as of December 31, 2025. The results for the performance period yielded a payout of 120 percent of target.

•In January 2024, the Company’s Board of Directors approved the 2024 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 645,318 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 468,708 phantom units were outstanding as of December 31, 2025, from which a minimum of zero to a maximum of 937,416 units could be awarded. Eligible employees also received cash incentives as part of the 2024 Performance Program, which totaled $11 million as of December 31, 2025. The ultimate payout will range from zero to $22 million at the end of a three-year performance period.

•In January 2025, the Company’s Board of Directors approved the 2025 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,028,112 units. The actual number of phantom units awarded will be between zero and 200 percent of target. A total of 871,793 phantom units were outstanding as of December 31, 2025, from which a minimum of zero to a maximum of 1,743,586 units could be awarded. Eligible employees also received cash incentives as part of the 2025 Performance Program, which totaled $14 million as of December 31, 2025. The ultimate payout will range from zero to $28 million at the end of a three-year performance period.

Compensation costs related to the conditional cash-settled awards are recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the cash-settled performance programs were expenses of $45 million and $2 million during 2025 and 2023, respectively and a net benefit of $13 million during 2024. Capitalized compensation costs under the cash-settled performance programs were expenses of approximately $3 million and $100 thousand during 2025 and 2023, respectively and a net benefit of approximately $1 million during 2024.

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023

	(In thousands)
Non-vested, beginning of year	3,972	4,629	4,835
Granted	1,605	834	1,536
Assumed awards from Callon acquisition	—	2,934	—
Vested	(2,066)	(4,222)	(1,593)
Forfeited	(353)	(203)	(99)
Expired	(242)	—	(50)
Non-vested, end of year(1)	2,916	3,972	4,629

(1)As of December 31, 2025, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $14 million.

In January 2026, the Company’s Board of Directors approved the 2026 Performance Program, pursuant to the 2016 Plan. A portion of the award is based upon measurement of TSR similar to prior year awards, and the remaining portion of the award is based on performance and financial objectives as defined in the 2026 Performance Program. Eligible employees received conditional phantom units and cash incentives. The conditional phantom units totaled 904,442 units, with the ultimate units to be awarded ranging from zero to a maximum of 1,808,884 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. These phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock, a Level 1 fair value measurement. The cash incentives totaled $14 million, with the ultimate payout ranging from zero to $28 million. Final payout of the awards will be determined at the end of a three-year performance period.

- Definition

The entire disclosure for equity.

+ References

+ Details

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	$ 44,892	$ 43,799
Unproved properties	615	899
Capitalized costs, gross	45,507	44,698
Accumulated DD&A	(32,967)	(32,304)
Capitalized costs, net	12,540	12,394
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	19,690	19,246
Unproved properties	384	711
Capitalized costs, gross	20,074	19,957
Accumulated DD&A	(11,220)	(11,053)
Capitalized costs, net	8,854	8,904
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	14,724	14,458
Unproved properties	99	67
Capitalized costs, gross	14,823	14,525
Accumulated DD&A	(12,558)	(12,299)
Capitalized costs, net	2,265	2,226
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	9,757	9,661
Unproved properties	0	0
Capitalized costs, gross	9,757	9,661
Accumulated DD&A	(9,189)	(8,952)
Capitalized costs, net	568	709
Other International
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved properties	721	434
Unproved properties	132	121
Capitalized costs, gross	853	555
Accumulated DD&A	0	0
Capitalized costs, net	$ 853	$ 555

RETIREMENT AND DEFERRED COMPENSATION PLANS - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50.00%
Maximum percentage of compensation contributed by the company	8.00%
Percentage of additional contribution to money purchase retirement plan	6.00%
Maximum percentage of eligible compensation contributed by the participating employees	50.00%
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested	75.00%
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested	20.00%
Annual cost of retirement benefit plans	$ 44	$ 46	$ 44
Targeted ongoing funding level of pension plan policy, percent	100.00%
Outperformance relative to gilts for equities	1.30%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 111	$ 102	$ 112
Expected contribution towards pension and postretirement plan	1
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 1

ASSET RETIREMENT OBLIGATION - Schedule of changes to Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the year	$ 2,694	$ 2,438
Liabilities incurred	23	15
Liabilities acquired	0	136
Liabilities divested	(8)	(272)
Liabilities settled	(100)	(70)
Accretion expense	158	148	$ 116
Revisions in estimated liabilities	113	299
Asset retirement obligation at end of the year	2,880	2,694	$ 2,438
Less current portion	(181)	(103)
Asset retirement obligation, long-term	$ 2,699	$ 2,591

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Schedule of Weighted Average Lease Term And Discount Rate

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2025:


	Operating Leases		Finance Lease
Weighted average remaining lease term	6.8 years		7.7 years
Weighted average discount rate	5.9	%	4.4	%

Schedule of Operating Lease, Liability, Maturity

At December 31, 2025, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)

	(In millions)
2026	$	103	$	4	$	243
2027	70		4		214
2028	53		4		182
2029	41		4		156
2030	25		4		119
Thereafter	136		14		57
Total future minimum payments	428		34		$	971
Less: imputed interest	(111)		(6)		N/A
Total lease liabilities	317		28		N/A
Current portion	97		3		N/A
Non-current portion	$	220	$	25	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(2)Amounts represent future payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $263 million, $245 million, and $182 million in 2025, 2024, and 2023, respectively.

Schedule of Finance Lease, Liability, Maturity

At December 31, 2025, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)

	(In millions)
2026	$	103	$	4	$	243
2027	70		4		214
2028	53		4		182
2029	41		4		156
2030	25		4		119
Thereafter	136		14		57
Total future minimum payments	428		34		$	971
Less: imputed interest	(111)		(6)		N/A
Total lease liabilities	317		28		N/A
Current portion	97		3		N/A
Non-current portion	$	220	$	25	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

Schedule of Long-term Purchase Commitment

At December 31, 2025, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)

	(In millions)
2026	$	103	$	4	$	243
2027	70		4		214
2028	53		4		182
2029	41		4		156
2030	25		4		119
Thereafter	136		14		57
Total future minimum payments	428		34		$	971
Less: imputed interest	(111)		(6)		N/A
Total lease liabilities	317		28		N/A
Current portion	97		3		N/A
Non-current portion	$	220	$	25	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

CAPITAL STOCK - Schedule of Restricted Stock Activities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Units
Assumed Awards from Callon acquisition (in shares)	0	1,498,000	0
Weighted Average Grant-Date Fair Value
Assumed Awards from Callon acquisition (in USD per share)	$ 0	$ 35.43	$ 0
Total compensation cost related to non-vested awards not yet recognized	$ 6
Total fair value of restricted stock awards vested	$ 26	$ 73	$ 23
Restricted Stock
Units
Non-vested, beginning balance (in shares)	1,415,000	1,480,000	1,885,000
Granted (in shares)	827,000	897,000	661,000
Vested (in shares)	(797,000)	(2,295,000)	(975,000)
Forfeited (in shares)	(282,000)	(165,000)	(69,000)
Expired (in shares)	0	0	(22,000)
Non-vested, ending balance (in shares)	1,163,000	1,415,000	1,480,000
Weighted Average Grant-Date Fair Value
Non-vested Beginning Balance (in USD per share)	$ 35.07	$ 30.69	$ 23.08
Granted (in USD per share)	23.29	33.48	41.60
Vested (in USD per share)	32.74	31.83	23.31
Forfeited (in USD per share)	31.40	35.48	32.44
Expired (in USD per share)	0	0	27.81
Non-vested Ending Balance (in USD per share)	$ 29.19	$ 35.07	$ 30.69
Weighted-average remaining life of unvested restricted stock units	9 months 18 days
Phantom Units
Units
Non-vested, beginning balance (in shares)	3,917,000	4,478,000	5,709,000
Granted (in shares)	2,302,000	2,369,000	1,972,000
Vested (in shares)	(1,887,000)	(2,568,000)	(2,851,000)
Forfeited (in shares)	(914,000)	(362,000)	(340,000)
Expired (in shares)	0	0	(12,000)
Non-vested, ending balance (in shares)	3,418,000	3,917,000	4,478,000
Weighted Average Grant-Date Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 38
Phantom Units Issued Based on Per-Share Market Price of Apache Common Stock
Units
Granted (in shares)	2,301,540	2,369,605	1,972,116
Stock Settled Restricted Stock Units
Units
Non-vested, beginning balance (in shares)
Non-vested, ending balance (in shares)	1,163,194
Weighted Average Grant-Date Fair Value
Total compensation cost related to non-vested awards not yet recognized	$ 10

CAPITAL STOCK - Schedule of Stock Options Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Shares Under Option
Outstanding, beginning of year (in shares)	1,416,000	1,465,000	2,078,000
Granted (in shares)	1,722,000	0	0
Exercised (in shares)	0	0	(12,183)
Forfeited (in shares)	(224,000)	0	0
Expired (in shares)	(139,000)	(49,000)	(601,000)
Outstanding, end of year, (in shares)	2,775,000	1,416,000	1,465,000
Expected to vest (in shares)	1,427,000	0	0
Exercisable, end of year (in shares)	1,348,000	1,416,000	1,465,000
Weighted Average Exercise Price
Outstanding, beginning of year (in USD per share)	$ 48.64	$ 48.48	$ 57.71
Granted (in USD per share)	23.26	0	0
Exercised (in USD per share)	0	0	42.38
Forfeited (in USD per share)	22.86	0	0
Expired (in USD per share)	48.47	43.91	80.53
Outstanding, end of year (in USD per share)	34.98	48.64	48.48
Expected to vest (in USD per share)	23.33	0	0
Exercisable, end of year (in USD per share)	$ 47.30	$ 48.64	$ 48.48
Weighted average remaining contractual life for options outstanding	1 year 6 months
Aggregate intrinsic value for options outstanding exercisable	$ 97,000
Weighted average remaining contractual life for exercisable	5 years 4 months 24 days
Aggregate intrinsic value for options outstanding	$ 2,000,000
Total unrecognized compensation	$ 6,000,000
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Nonvested, Number of Shares	1,426,518

NATURE OF OPERATIONS (Details)	12 Months Ended
NATURE OF OPERATIONS (Details)	Dec. 31, 2025 Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	3

ACQUISITIONS AND DIVESTITURES - 2024 Activity (Details) shares in Millions				3 Months Ended		12 Months Ended
	Dec. 31, 2024 USD ($)	Apr. 01, 2024 USD ($) shares	Mar. 18, 2024 USD ($)	Dec. 31, 2024 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Business Combination [Line Items]
Payments to acquire leasehold and property							$ 60,000,000
Proceeds from asset divestitures						$ 611,000,000	1,609,000,000	$ 29,000,000
Proceeds from sale of Kinetik shares						0	428,000,000	228,000,000
Kinetik
Business Combination [Line Items]
Proceeds from sale of Kinetik shares			$ 428,000,000
Proved properties:
Business Combination [Line Items]
Impairments						$ 18,000,000	1,111,000,000	0
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Combination [Line Items]
Proceeds from asset divestitures							91,000,000	29,000,000
Gain (loss) on sale of oil and gas properties							(22,000,000)	$ (8,000,000)
TEXAS \| Disposed of by Sale
Business Combination [Line Items]
Carrying value of non-core assets disposed	$ 347,000,000			$ 347,000,000			347,000,000
Proceeds from asset divestitures							255,000,000
Asset retirement obligation assumed							42,000,000
Gain (loss) on sale of oil and gas properties							50,000,000
Permian Region \| Disposed of by Sale
Business Combination [Line Items]
Carrying value of non-core assets disposed	1,100,000,000			1,100,000,000			1,100,000,000
Asset retirement obligation assumed	224,000,000
Gain (loss) on sale of oil and gas properties				5,000,000
Permian Region \| Disposed of by Sale \| Proved properties:
Business Combination [Line Items]
Impairments					$ 315,000,000
Permian Region \| Disposed of by Sale \| Non-Core Mineral And Royalty Interests
Business Combination [Line Items]
Carrying value of non-core assets disposed	71,000,000			$ 71,000,000			71,000,000
Proceeds from asset divestitures							394,000,000
Gain (loss) on sale of oil and gas properties							(321,000,000)
Permian Region \| Disposal Group, Held-for-Sale
Business Combination [Line Items]
Proceeds from asset divestitures	$ 869,000,000
Callon Petroleum Company
Business Combination [Line Items]
Consideration transferred		$ 4,500,000,000
Business acquisition, equity interests exchange ratio		1.0425
Business acquisition, equity interest issued or issuable, number of shares (in shares) \| shares		70
Revenue of acquiree since acquisition date							1,200,000,000
Net income of acquiree since acquisition date							$ 262,000,000

RETIREMENT AND DEFERRED COMPENSATION PLANS - Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 136
Fair value of plan assets at end of year	147	$ 136
Pension Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	107	118	$ 108
Service cost	1	1	1
Interest cost	6	6	5
Foreign currency exchange rates	8	(2)	6
Actuarial losses (gains)	(1)	(11)	3
Plan curtailments	0	0	0
Benefits paid	(6)	(5)	(5)
Retiree contributions	0	0	0
Projected benefit obligation at end of year	115	107	118
Change in Plan Assets
Fair value of plan assets at beginning of year	136	150	137
Actual return (loss) on plan assets	5	(8)	8
Foreign currency exchange rates	10	(3)	8
Employer contributions	2	2	2
Benefits paid	(6)	(5)	(5)
Retiree contributions	0	0	0
Fair value of plan assets at end of year	147	136	150
Funded status at end of year	32	29	32
Amounts recognized in Consolidated Balance Sheet
Current liability	0	0	0
Non-current asset	32	29	32
Amounts recognized in Consolidated Balance Sheet	32	29	32
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (18)	$ (16)	$ (12)
Weighted Average Assumptions used as of December 31
Discount rate	5.60%	5.60%	4.80%
Salary increases	4.50%	4.70%	4.60%
Expected return on assets	5.60%	5.70%	4.80%
Postretirement Benefits
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$ 15	$ 15	$ 15
Service cost	1	1	1
Interest cost	1	1	1
Foreign currency exchange rates	0	0	0
Actuarial losses (gains)	(1)	0	0
Plan curtailments	0	(1)	0
Benefits paid	(2)	(2)	(3)
Retiree contributions	1	1	1
Projected benefit obligation at end of year	15	15	15
Change in Plan Assets
Fair value of plan assets at beginning of year	0	0	0
Actual return (loss) on plan assets	0	0	0
Foreign currency exchange rates	0	0	0
Employer contributions	1	1	1
Benefits paid	(2)	(2)	(3)
Retiree contributions	1	1	2
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	(15)	(15)	(15)
Amounts recognized in Consolidated Balance Sheet
Current liability	(1)	(2)	(2)
Non-current liability	(14)	(13)	(13)
Amounts recognized in Consolidated Balance Sheet	(15)	(15)	(15)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 14	$ 14	$ 16
Weighted Average Assumptions used as of December 31
Discount rate	5.18%	5.49%	5.00%
Healthcare cost trend
Initial	7.00%	6.50%	6.25%
Ultimate in 2032	5.25%	5.25%	5.25%

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.

The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions.

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. The Company has determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a variable interest entity (VIE) under GAAP. Apache consolidates the activities of APA’s Egyptian operations because it has concluded that a wholly owned subsidiary has a controlling financial interest in APA’s Egyptian operations and was determined to be the primary beneficiary of the VIE.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements, and changes in these estimates are recorded when known.

Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2—Acquisitions and Divestitures), the assessment of asset retirement obligations (refer to Note 7—Asset Retirement Obligation), the estimate of income taxes (refer to Note 9—Income Taxes), the estimation of the contingent liability representing Apache’s potential decommissioning obligations on sold properties in the Gulf of America (refer to Note 10—Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 16—Supplemental Oil and Gas Disclosures (Unaudited)).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Refer to Note 4—Derivative Instruments and Hedging Activities, Note 8—Debt and Financing Costs, and Note 11—Retirement and Deferred Compensation Plans for further detail regarding the Company’s fair value measurements recorded on a recurring basis.

The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment or when allocating the purchase price for acquired assets and liabilities in a business combination.

The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature and maturities of these instruments.

Impairments

The Company recorded $37 million and $11 million of asset impairments in connection with fair value assessments during the years ended December 31, 2025 and 2023, respectively.

During 2024, the Company performed an 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 that expected returns did not economically support making investments required under the combined impact of the regulations and expects to cease production at its facilities in the North Sea prior to 2030. As a result, the Company performed a fair value assessment of the present value of its oil and gas assets in the North Sea as of the third quarter of 2024. Accordingly, the Company recognized impairments of $796 million on certain proved properties in the North Sea, which were written down to their estimated fair values as of the third quarter of 2024. This impairment is discussed in further detail below in “Property and Equipment — Oil and Gas Property.”

Additionally, in the third quarter of 2024, the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin. As a result, a separate impairment analysis was performed for each of the assets within the disposal group. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The historical carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in an impairment totaling $315 million on the Company’s proved properties in the U.S. Refer to Note 2—Acquisitions and Divestitures for more detail.

Allocation of Purchase Price

During 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 transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired, and liabilities assumed be recognized at their fair values as of the acquisition date, using various Level 3 fair value measurements. Material assets and liabilities acquired are discussed further below:

•The most significant assumptions relate to the estimated fair values assigned to proved oil and natural gas properties. The fair value of proved oil and natural gas properties as of the acquisition date were estimated using the income approach, where fair value was determined based on the expected future cash flows from estimated proved oil, natural gas, and NGL reserves and related discounted future net cash flows as of that date. Significant inputs to the fair value estimate included estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted-average cost of capital discount rate.

•The fair value of unproved properties was estimated mainly using the market approach, based on acreage costs in areas where Callon acreage was acquired.

•The fair value of most other current assets and current liabilities were determined to be equivalent to the carrying value due to their short-term nature.

•The fair value of debt was based on the estimated cost to retire Callon’s debt instruments.

•Estimated deferred taxes were based on available information concerning the fair values assigned to acquired assets and liabilities and their respective tax basis and tax-related carryforwards at the acquisition date.

Refer to Note 2—Acquisitions and Divestitures for further detail regarding the Company’s fair value measurements recorded related to the Callon acquisition.

Revenue Recognition

The Company’s oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third parties to provide flexibility to fulfill sales obligations and commitments. Under these commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.

APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves.

Refer to Note 16—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Payment Terms and Contract Balances

Receivables from contracts with customers, including receivables for purchased oil and gas sales and net of allowance for credit losses, were $826 million and $1.7 billion as of December 31, 2025 and 2024, respectively. Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. During 2025, the Company observed a meaningful improvement in the timing of payments from the Egyptian General Petroleum Corporation (EGPC). As a result of more consistent remittances during the year, the Company’s outstanding receivable balance from this customer was current as of December 31, 2025. This improvement follows several periods prior to 2025 during which EGPC payments were delayed and the receivable balance increased. While recent collections have been timely, the Company continues to closely monitor its exposure to EGPC, as payment patterns may vary over time.

In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2025 and 2024, the Company had $516 million and $625 million, respectively, of cash and cash equivalents. The Company had no restricted cash as of December 31, 2025 and 2024.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for expected credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity.

The following table presents changes to the Company’s allowance for credit loss:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Allowance for credit loss at beginning of year	$	123	$	114	$	117
Additional provisions for the year	20		9		16
Uncollectible accounts written off, net of recoveries	(3)		—		(19)
Allowance for credit loss at end of year	$	140	$	123	$	114

Inventories

Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.

During 2025, the Company recorded $7 million of inventory impairments in the North Sea. During 2024, the Company recorded $18 million of inventory impairments, including $13 million in the North Sea and $5 million in the U.S. During 2023, the Company recorded impairments of approximately $50 million in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

Property and Equipment

The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations and acquisitions, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Proved properties:
U.S.	$	—	$	315	$	—
Egypt	18		—		—
North Sea	—		796		—
Total proved properties	$	18	$	1,111	$	—

Unproved properties:
U.S.	$	—	$	34	$	10
Egypt	2		—		—
North Sea	—		—		11
Other International	—		1		1
Total unproved properties	$	2	$	35	$	22

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement. During the year ended December 31, 2025, the Company recorded $18 million of impairments to its proved properties in Egypt.

During 2024, the Company updated its cessation-of-production dates for its North Sea operations, as discussed above in “Fair Value Measurements.” This change significantly altered the Company’s remaining oil and gas reserves in the North Sea and triggered an impairment assessment of the Company’s proved oil and gas properties at the end of the third quarter of 2024. Future production volumes and estimated future commodity prices are the largest drivers in the variability of future cash flows. Expected cash flows were estimated based on management’s views of forward pricing as of the balance sheet dates. A discount rate based on a market-based weighted-average cost of capital estimate was applied to the undiscounted cash flow estimate to value the Company’s North Sea assets. In connection with this assessment, the Company recorded impairments totaling $796 million on certain of the Company’s North Sea proved properties to an aggregate fair value of $263 million.

For the year ended December 31, 2023, the Company recorded no impairments of proved properties.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission (GPT) Facilities

GPT facilities totaled $445 million and $433 million at December 31, 2025 and 2024, respectively, with accumulated depreciation for these assets totaling $383 million and $364 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within, or close to, those fields.

For the year ended December 31, 2025, the Company recorded $1 million in impairments of GPT facilities in Egypt. For each of the years ended December 31, 2024 and 2023, the Company recorded no impairments of GPT facilities.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment, net of accumulated depreciation totaled $146 million and $183 million at December 31, 2025 and 2024, respectively.

For the year ended December 31, 2025, the Company recorded an $18 million impairment for the anticipated sale of an office building.

Asset Retirement Costs and Obligations

The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Capitalized Interest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored and significant exploration and development projects that have not commenced production that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 10—Commitments and Contingencies.

Derivative Instruments and Hedging Activities

The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.

All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 4—Derivative Instruments and Hedging Activities for further information.

Income Taxes

The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. Refer to Note 9—Income Taxes for further information.

In December 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2023-09, Improvements to Income Tax Disclosures (ASU 2023-09). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income from continuing operations, income tax (expense) benefit, and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among other items. This ASU is effective for annual reporting periods beginning after December 15, 2024. ASU 2023-09 should be applied on a prospective basis, although retrospective application is permitted. The Company adopted ASU 2023-09 retrospectively for the year ended December 31, 2025, and it did not have a material impact on the Company’s financial statements.

Earnings Per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.

Stock-Based Compensation

The Company grants various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on the Company’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s stock-based compensation plans and related accounting policies are defined and described more fully in Note 12—Capital Stock.

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

Transaction, Reorganization, and Separation (TRS)

The Company recorded TRS costs in 2025 totaling $102 million, which comprised primarily employee separations in the U.S. and organization restructuring in the North Sea.

The Company recorded TRS costs in 2024 totaling $168 million, which primarily comprised $147 million associated with the Callon acquisition, including $76 million of separation costs and $71 million of transaction and integration costs.

The Company recorded TRS costs in 2023 totaling $15 million including $7 million related to consulting and separation costs in international operations.

New Pronouncements Issued But Not Yet Adopted

In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40),” which expands disclosures around a public entity’s costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2025

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Current Assets

The following table provides detail of the Company’s other current assets as of December 31:


	2025		2024

	(In millions)
Inventories	$	351	$	425
Drilling advances	93		184

Current decommissioning security for sold Gulf of America assets	19		157
Prepaid assets and other	80		54
Total Other current assets	$	543	$	820

CAPITAL STOCK (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Common Stock Outstanding

The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023
Balance, beginning of year	365,397,149	303,575,901	311,559,149
Shares issued for stock-based compensation plans:
Treasury shares issued	—	—	2,016
Common shares issued	458,481	70,983,745	725,914
Treasury shares acquired	(12,890,984)	(9,162,497)	(8,711,178)
Balance, end of year	352,964,646	365,397,149	303,575,901

Schedule of Reconciliation of Components of Basic and Diluted Net Income (Loss) Per Common Share

The following table provides a reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2025, 2024, and 2023:


	2025					2024					2023
	Income		Shares	Per Share		Income		Shares	Per Share		Income		Shares	Per Share

	(In millions, except per share amounts)
Basic:


Income attributable to common stock	$	1,434	359	$	3.99	$	804	353	$	2.28	$	2,855	308	$	9.26
Effect of Dilutive Securities:
Stock compensation awards	$	—	—	$	—	$	—	—	$	(0.01)	$	—	1	$	(0.01)
Diluted:


Income attributable to common stock	$	1,434	359	$	3.99	$	804	353	$	2.27	$	2,855	309	$	9.25

Schedule of Description of Stock Based Compensation Plans and Related Costs

The following table summarizes the Company’s stock-settled and cash-settled compensation costs for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Stock-settled and cash-settled compensation expensed:
Lease operating expenses	$	26	$	16	$	27
Exploration	7		4		7
General and administrative	74		29		50
Total stock-settled and cash-settled compensation expensed	107		49		84
Stock-settled and cash-settled compensation capitalized	15		9		13
Total stock-settled and cash-settled compensation costs	$	122	$	58	$	97

Schedule of Stock Options Activities

The following table summarizes stock option activity for the years ended December 31, 2025, 2024, and 2023:


	2025			2024			2023
	Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price		Shares Under Option	Weighted Average Exercise Price

	(In thousands, except exercise price amounts)
Outstanding, beginning of year	1,416	$	48.64	1,465	$	48.48	2,078	$	57.71
Granted	1,722	23.26		—	—		—	—
Exercised	—	—		—	—		(12)	42.38
Forfeited	(224)	22.86		—	—		—	—
Expired	(139)	48.47		(49)	43.91		(601)	80.53
Outstanding, end of year(1)	2,775	34.98		1,416	48.64		1,465	48.48
Expected to vest	1,427	23.33		—	—		—	—
Exercisable, end of year(1)(2)	1,348	47.30		1,416	48.64		1,465	48.48

(2)As of December 31, 2025, there was $6 million of total unrecognized compensation cost related to 1,426,518 unvested stock options.

Schedule of Share-Based Payment Award, Stock Options, Valuation Assumptions


	2025			2024	2023
Expected volatility	57.37		%	N/A	N/A
Expected dividend yields	4.30		%	N/A	N/A
Expected term (in years)	6			N/A	N/A
Risk-free rate	4.43		%	N/A	N/A
Weighted-average grant-date fair value	$	9.50		N/A	N/A

Schedule of Restricted Stock and Restricted Stock Units Activity

The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2025, 2024, and 2023:


	2025			2024			2023
	Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value		Units	Weighted Average Grant-Date Fair Value

	(In thousands, except per share amounts)
Non-vested, beginning of year	1,415	$	35.07	1,480	$	30.69	1,885	$	23.08
Granted	827	23.29		897	33.48		661	41.60
Assumed awards from Callon acquisition	—	—		1,498	35.43		—	—
Vested(3)	(797)	32.74		(2,295)	31.83		(975)	23.31
Forfeited	(282)	31.40		(165)	35.48		(69)	32.44
Expired	—	—		—	—		(22)	27.81
Non-vested, end of year(1)(2)	1,163	29.19		1,415	35.07		1,480	30.69

(1)As of December 31, 2025, there was $10 million of total unrecognized compensation cost related to 1,163,194 unvested stock-settled restricted stock units.

(2)As of December 31, 2025, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.

(3)The grant date fair values of the stock-settled awards vested during 2025, 2024, and 2023 were $26 million, $73 million, and $23 million, respectively.

The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023

	(In thousands)
Non-vested, beginning of year	3,917	4,478	5,709

Granted(1)	2,302	2,369	1,972
Vested	(1,887)	(2,568)	(2,851)
Forfeited	(914)	(362)	(340)
Expired	—	—	(12)
Non-vested, end of year(2)	3,418	3,917	4,478

(1)Restricted stock phantom units granted during 2025, 2024, and 2023 included 2,301,540, 2,369,605, and 1,972,116 awards, respectively, based on the per-share market price of APA common stock.

(2)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2025 was approximately $38 million.

The following table summarizes cash-settled conditional restricted stock phantom unit activity for the years ended December 31, 2025, 2024, and 2023:


	For the Year Ended December 31,
	2025	2024	2023

	(In thousands)
Non-vested, beginning of year	3,972	4,629	4,835
Granted	1,605	834	1,536
Assumed awards from Callon acquisition	—	2,934	—
Vested	(2,066)	(4,222)	(1,593)
Forfeited	(353)	(203)	(99)
Expired	(242)	—	(50)
Non-vested, end of year(1)	2,916	3,972	4,629

(1)As of December 31, 2025, the outstanding liability for the unvested cash-settled conditional restricted stock phantom units that had not been recognized was approximately $14 million.

RETIREMENT AND DEFERRED COMPENSATION PLANS - Expected Future Benefit Payment (Details) $ in Millions	Dec. 31, 2025 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	$ 5
2027	7
2028	7
2029	7
2030	7
Years 2031-2035	39
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2026	1
2027	1
2028	1
2029	1
2030	1
Years 2031-2035	$ 7

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

COMMITMENTS AND CONTINGENCIES - Schedule of Weighted Average Lease Term And Discount Rate (Details)	Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]
Operating leases, weighted average remaining lease term	6 years 9 months 18 days
Finance leases, weighted average remaining lease term	7 years 8 months 12 days
Operating leases, weighted average discount rate	5.90%
Finance leases, weighted average discount rate	4.40%

CAPITAL STOCK - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		12 Months Ended
	Jan. 31, 2026	Sep. 30, 2022	Dec. 31, 2021	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive (in shares)				3,300,000	2,000,000.0	1,900,000
Additional number of shares authorized to be repurchased (in shares)		40,000,000	40,000,000
Treasury shares acquired (in shares)				12,890,984	9,162,497	8,711,178
Treasure stock acquired, average price (in USD per share)				$ 21.73	$ 26.83	$ 37.81
Remaining authorized repurchase amount (in shares)				21,900,000
Common stock, dividends, per share (in USD per share)				$ 1.00	$ 1.00	$ 1.00
Shares authorized and available for grant (in shares)				5,200,000
Total stock-settled and cash-settled compensation expensed				$ 107	$ 49	$ 84
Stock-settled and cash-settled compensation capitalized				$ 15	$ 9	$ 13
Shares issued in the period (in shares)				1,721,990	0	0
Exercised (in shares)				0	0	12,183
Common stock issued (in shares)				2,775,000	1,416,000	1,465,000	2,078,000
Expected term				6 years
Total compensation cost related to non-vested awards not yet recognized				$ 6
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable				3 years
Period in which stock options expires after grant date				10 years
Total stock-settled and cash-settled compensation expensed				$ 8
Stock-settled and cash-settled compensation capitalized				1
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed				46	$ 53	$ 73
Stock-settled and cash-settled compensation capitalized				$ 10	$ 9	$ 11
Awards granted during period (in shares)				827,000	897,000	661,000
Weighted average grant date fair value per share (in USD per share)				$ 23.29	$ 33.48	$ 41.60
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)				2,302,000	2,369,000	1,972,000
Total compensation cost related to non-vested awards not yet recognized				$ 38
Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Expected term	3 years
Weighted average grant date fair value per share (in USD per share)	$ 23.88
Subsequent Event \| Omnibus Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 15
Common stock issued (in shares)	1,487,317
Weighted average grant date fair value (in dollars per share)	$ 9.75
Subsequent Event \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	624,467
Total compensation cost related to non-vested awards not yet recognized	$ 15
Subsequent Event \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,115,116
Total compensation cost related to non-vested awards not yet recognized	$ 51
Award, remeasurement basis (in shares)	1

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Oil and Gas Reserve Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2025 MBoe MBbls MMcf	Dec. 31, 2024 MBoe MBbls MMcf	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	734,353	670,003	735,859	801,315
Proved undeveloped reserves	321,864	299,094	71,621	88,454
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	969,097	807,480	889,769
Extensions, discoveries and other additions	100,478	324,624	112,249
Purchases of minerals in-place		222,121	64
Revisions of previous estimates	174,766	(74,149)	(45,931)
Production	(169,500)	(166,426)	(147,840)
Sales of minerals in-place	(18,624)	(144,553)	(831)
Ending balance	1,056,217	969,097	807,480
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	545,555	482,677	500,354	530,823
Proved undeveloped reserves	235,867	213,253	65,931	76,386
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	695,930	566,285	607,209
Extensions, discoveries and other additions	71,913	222,811	95,677
Purchases of minerals in-place		222,121	64
Revisions of previous estimates	137,155	(67,162)	(56,532)
Production	(104,952)	(103,572)	(79,302)
Sales of minerals in-place	(18,624)	(144,553)	(831)
Ending balance	781,422	695,930	566,285
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	163,639	151,474	165,162	174,633
Proved undeveloped reserves	12,208	12,204	5,690	8,735
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	163,678	170,852	183,368
Extensions, discoveries and other additions	28,565	28,176	15,344
Purchases of minerals in-place		0	0
Revisions of previous estimates	36,960	14,986	24,490
Production	(53,356)	(50,336)	(52,350)
Sales of minerals in-place	0	0	0
Ending balance	175,847	163,678	170,852
Egypt \| Noncontrolling interest - Egypt
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved developed reserves (Energy) \| MBoe	59	55	57	61
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	25,159	35,852	70,343	95,859
Proved undeveloped reserves	0	0	0	3,333
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	35,852	70,343	99,192
Extensions, discoveries and other additions	0	0	1,228
Purchases of minerals in-place		0	0
Revisions of previous estimates	499	(21,973)	(13,889)
Production	(11,192)	(12,518)	(16,188)
Sales of minerals in-place	0	0	0
Ending balance	25,159	35,852	70,343
Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	0	0	0	0
Proved undeveloped reserves	73,789	73,637	0	0
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	73,637	0	0
Extensions, discoveries and other additions	0	73,637	0
Purchases of minerals in-place		0	0
Revisions of previous estimates	152	0	0
Production	0	0	0
Sales of minerals in-place	0	0	0
Ending balance	73,789	73,637	0
Crude Oil and Condensate
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	306,186	311,170	342,923	368,338
Proved undeveloped reserves	202,446	188,541	36,202	33,669
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	499,711	379,125	402,007
Extensions, discoveries and other additions	57,450	192,530	56,893
Purchases of minerals in-place		124,112	20
Revisions of previous estimates	45,710	(20,121)	(5,017)
Production	(86,662)	(89,267)	(74,003)
Sales of minerals in-place	(7,577)	(86,668)	(775)
Ending balance	508,632	499,711	379,125
Crude Oil and Condensate \| United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	182,300	184,744	179,542	177,708
Proved undeveloped reserves	121,079	107,283	30,948	22,239
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	292,027	210,490	199,947
Extensions, discoveries and other additions	39,804	100,778	43,613
Purchases of minerals in-place		124,112	20
Revisions of previous estimates	24,942	(9,642)	(3,520)
Production	(45,817)	(47,043)	(28,795)
Sales of minerals in-place	(7,577)	(86,668)	(775)
Ending balance	303,379	292,027	210,490
Crude Oil and Condensate \| Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	101,750	95,990	102,305	108,050
Proved undeveloped reserves	7,578	7,621	5,254	8,557
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	103,611	107,559	116,607
Extensions, discoveries and other additions	17,646	18,115	12,979
Purchases of minerals in-place		0	0
Revisions of previous estimates	20,088	10,521	10,505
Production	(32,017)	(32,584)	(32,532)
Sales of minerals in-place	0	0	0
Ending balance	109,328	103,611	107,559
Crude Oil and Condensate \| Egypt \| Noncontrolling interest - Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	36,000	35,000	36,000	39,000
Crude Oil and Condensate \| North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	22,136	30,436	61,076	82,580
Proved undeveloped reserves	0	0	0	2,873
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	30,436	61,076	85,453
Extensions, discoveries and other additions	0	0	301
Purchases of minerals in-place		0	0
Revisions of previous estimates	528	(21,000)	(12,002)
Production	(8,828)	(9,640)	(12,676)
Sales of minerals in-place	0	0	0
Ending balance	22,136	30,436	61,076
Crude Oil and Condensate \| Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	0	0	0	0
Proved undeveloped reserves	73,789	73,637	0	0
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	73,637	0	0
Extensions, discoveries and other additions	0	73,637	0
Purchases of minerals in-place		0	0
Revisions of previous estimates	152	0	0
Production	0	0	0
Sales of minerals in-place	0	0	0
Ending balance	73,789	73,637	0
Natural Gas Liquids
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	181,589	154,267	154,946	160,975
Proved undeveloped reserves	58,438	54,674	18,401	19,080
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	208,941	173,347	180,055
Extensions, discoveries and other additions	16,232	62,988	26,082
Purchases of minerals in-place		51,406	21
Revisions of previous estimates	48,466	(20,444)	(9,332)
Production	(28,295)	(27,478)	(23,446)
Sales of minerals in-place	(5,317)	(30,878)	(33)
Ending balance	240,027	208,941	173,347
Natural Gas Liquids \| United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	180,690	153,523	153,486	158,745
Proved undeveloped reserves	58,438	54,674	18,401	19,004
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	208,197	171,887	177,749
Extensions, discoveries and other additions	16,232	62,988	25,711
Purchases of minerals in-place		51,406	21
Revisions of previous estimates	47,852	(20,167)	(8,568)
Production	(27,836)	(27,039)	(22,993)
Sales of minerals in-place	(5,317)	(30,878)	(33)
Ending balance	239,128	208,197	171,887
Natural Gas Liquids \| North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves	899	744	1,460	2,230
Proved undeveloped reserves	0	0	0	76
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance	744	1,460	2,306
Extensions, discoveries and other additions	0	0	371
Purchases of minerals in-place		0	0
Revisions of previous estimates	614	(277)	(764)
Production	(459)	(439)	(453)
Sales of minerals in-place	0	0	0
Ending balance	899	744	1,460
Natural Gas
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves \| MMcf	1,479,471	1,227,393	1,427,939	1,632,012
Proved undeveloped reserves \| MMcf	365,880	335,274	102,107	214,234
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	1,562,667	1,530,046	1,846,246
Extensions, discoveries and other additions \| MMcf	160,778	414,633	175,641
Purchases of minerals in-place		279,615	136
Revisions of previous estimates	483,540	(201,502)	(189,496)
Production	(327,257)	(298,086)	(302,345)
Sales of minerals in-place	(34,377)	(162,039)	(136)
Ending balance \| MMcf	1,845,351	1,562,667	1,530,046
Natural Gas \| United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves \| MMcf	1,095,395	866,460	1,003,956	1,166,218
Proved undeveloped reserves \| MMcf	338,100	307,775	99,495	210,862
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	1,174,235	1,103,451	1,377,080
Extensions, discoveries and other additions \| MMcf	95,264	354,267	158,118
Purchases of minerals in-place \| MMcf		279,615	136
Revisions of previous estimates \| MMcf	386,166	(224,118)	(266,664)
Production \| MMcf	(187,793)	(176,941)	(165,083)
Sales of minerals in-place \| MMcf	(34,377)	(162,039)	(136)
Ending balance \| MMcf	1,433,495	1,174,235	1,103,451
Natural Gas \| Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves \| MMcf	371,335	332,905	377,144	399,502
Proved undeveloped reserves \| MMcf	27,780	27,499	2,612	1,068
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	360,404	379,756	400,570
Extensions, discoveries and other additions \| MMcf	65,514	60,366	14,188
Purchases of minerals in-place		0	0
Revisions of previous estimates	101,230	26,792	83,907
Production	(128,033)	(106,510)	(118,909)
Sales of minerals in-place	0	0	0
Ending balance \| MMcf	399,115	360,404	379,756
Natural Gas \| Egypt \| Noncontrolling interest - Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves \| MMcf	133,000	120,000	127,000	134,000
Natural Gas \| North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Proved developed reserves \| MMcf	12,741	28,028	46,839	66,292
Proved undeveloped reserves \| MMcf	0	0	0	2,304
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning balance \| MMcf	28,028	46,839	68,596
Extensions, discoveries and other additions \| MMcf	0	0	3,335
Purchases of minerals in-place		0	0
Revisions of previous estimates	(3,856)	(4,176)	(6,739)
Production	(11,431)	(14,635)	(18,353)
Sales of minerals in-place	0	0	0
Ending balance \| MMcf	12,741	28,028	46,839

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Positions

As of December 31, 2025, the Company had the following open natural gas financial basis swap contracts:

Basis Swap Purchased

Basis Swap Sold

Production Period

Settlement Index

MMBtu
(in 000’s)

Weighted Average Price Differential

MMBtu
(in 000’s)

Weighted Average Price Differential

January—December 2026

NYMEX Henry Hub/IF Waha

89,425

$(1.96)

—

Schedule of Derivative Liabilities at Fair Value

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
December 31, 2025



Liabilities:
Commodity derivative instruments	$	—	$	77	$	—	$	77	$	—	$	77



December 31, 2024


Liabilities:

Contingent consideration arrangements	$	—	$	18	$	—	$	18	$	—	$	18

(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

Schedule of Derivative Instruments on Consolidated Balance Sheet and Statement of Consolidated Operations

The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	For the Year Ended December 31,
	2025		2024

	(In millions)




Current Liabilities: Other current liabilities	$	77	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	$	—	$	18
Total derivative liabilities	$	77	$	18

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Realized:
Commodity derivative instruments	$	31	$	2	$	48
Contingent consideration arrangements	(7)		(4)		—



Realized gains (losses), net	24		(2)		48
Unrealized:
Commodity derivative instruments	(77)		(6)		51
Contingent consideration arrangements	—		(2)		—



Unrealized gains (losses), net	(77)		(8)		51
Derivative instrument gains (losses), net	$	(53)	$	(10)	$	99

DEBT AND FINANCING COSTS - Unsecured Committed Term Loan Facility (Details) - Unsecured Debt - USD ($)	Jan. 10, 2025	Dec. 31, 2024	Apr. 01, 2024
Debt Instrument [Line Items]
Debt instrument, face amount	$ 850,000,000
Term Loan Credit Agreement, Three Year Tranche Loans
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,500,000,000
Line of credit outstanding		$ 900,000,000

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
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-Name Accounting Standards Codification
-Section S50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-4

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-3

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
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-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (SX 210.4-08(f))
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
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-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 10: http://www.xbrl.org/2003/role/exampleRef
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69C

Reference 11: http://www.xbrl.org/2003/role/exampleRef
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-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69E

Reference 12: http://www.xbrl.org/2003/role/exampleRef
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-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69F

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 15: http://www.xbrl.org/2003/role/exampleRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1B

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (a)
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
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Reference 24: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1E

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1F
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1F

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1F
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1F

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1F

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1F
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1F

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1I

Reference 30: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
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-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 31: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482900/835-30-50-1

+ Details

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

CAPITALIZED EXPLORATORY WELL COSTS - Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging (Details) $ in Millions	Dec. 31, 2025 USD ($) Project	Dec. 31, 2024 USD ($) Project	Dec. 31, 2023 USD ($) Project	Dec. 31, 2022 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 158	$ 107	$ 156
Exploratory well costs capitalized for a period greater than one year	180	130	430
Capitalized well costs at end of year	$ 338	$ 237	$ 586	$ 474
Number of projects with exploratory well costs capitalized for a period greater than one year \| Project	7	12	33

CONSOLIDATED BALANCE SHEET (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Receivables, allowance	$ 140	$ 123
Common stock, par value (in USD per share)	$ 0.625	$ 0.625
Common stock, shares authorized (in shares)	860,000,000	860,000,000
Common stock, shares issued (in shares)	492,038,127	491,579,646
Treasury stock, shares (in shares)	139,073,481	126,182,497

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of Allowance for Credit Losses

The following table presents changes to the Company’s allowance for credit loss:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Allowance for credit loss at beginning of year	$	123	$	114	$	117
Additional provisions for the year	20		9		16
Uncollectible accounts written off, net of recoveries	(3)		—		(19)
Allowance for credit loss at end of year	$	140	$	123	$	114

Schedule of Non-cash Impairment Charges of Proved and Unproved Properties

The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Proved properties:
U.S.	$	—	$	315	$	—
Egypt	18		—		—
North Sea	—		796		—
Total proved properties	$	18	$	1,111	$	—

Unproved properties:
U.S.	$	—	$	34	$	10
Egypt	2		—		—
North Sea	—		—		11
Other International	—		1		1
Total unproved properties	$	2	$	35	$	22

OTHER CURRENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2025

Payables and Accruals [Abstract]

Schedule of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities as of December 31:


	2025		2024

	(In millions)
Accrued operating expenses	$	129	$	204
Accrued exploration and development	289		460

Accrued compensation and benefits	265		223
Accrued interest	88		93
Accrued income taxes	112		221
Current asset retirement obligation	181		103
Current operating lease liability	97		118

Current decommissioning contingency for sold Gulf of America properties	99		88
Other	227		168
Total Other current liabilities	$	1,487	$	1,678

RETIREMENT AND DEFERRED COMPENSATION PLANS - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 147	$ 136
Multi-asset credit
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	90	84
Nominal bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	6
Inflation-linked bonds
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	53	45
Cash
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 1	$ 1

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
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Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

INCOME TAXES - Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount
U.S. federal statutory tax rate	$ 586	$ 322	$ 605
State and local income taxes, net of federal income tax effect	31	2	(23)
Tax credits:
Cross-border tax laws	1	1	1
Corporate alternative minimum tax credit	71	(74)	0
Other tax credits	(1)	(3)	0
Foreign tax credits	269	0	0
Non-taxable or non-deductible items:
Stock compensation	1	17	(2)
Legal reserves	0	14	0
Transaction costs	0	5	0
U.S tax basis of investment in U.K.	0	(214)	0
Other	(1)	10	8
Changes in unrecognized tax benefits	(16)	2	5
Corporate alternative minimum tax	(71)	74	0
Other adjustments	(3)	3	0
Total	$ 1,099	$ 417	$ (324)
% of Income Before Income Taxes
U.S. federal statutory tax rate	21.00%	21.00%	21.00%
State and local income taxes, net of federal income tax effect	1.10%	0.10%	(0.80%)
Cross-border tax laws	0.00%	0.10%	0.00%
Tax credits:
Corporate alternative minimum tax credit	0.025	(0.048)	0
Other tax credits	0.00%	(0.20%)	0.00%
Foreign tax credits	9.60%	0.00%	0.00%
Non-taxable or non-deductible items:
Stock compensation	0.00%	1.10%	(0.10%)
Legal reserves	0	0.009	0
Transaction costs	0	0.003	0
U.S tax basis of investment in U.K.	0	(0.139)	0
Other	0.00%	0.70%	0.30%
Changes in unrecognized tax benefits	(0.006)	0.001	0.002
Corporate alternative minimum tax	(0.025)	0.048	0
Other adjustments	(0.10%)	0.20%	0.00%
Effective Income Tax Rate Reconciliation, Percent	39.40%	27.20%	(11.20%)
Egypt
Amount
Foreign tax effects	$ 277	$ 334	$ 366
Concessions on production-sharing contracts	$ 75	$ 77	$ 65
% of Income Before Income Taxes
Foreign tax effects	9.90%	21.80%	12.70%
Concessions on production-sharing contracts	2.80%	5.00%	2.30%
U.K.:
Amount
Foreign tax effects	$ 4	$ (376)	$ 283
Enacted changes in tax law	78	0	174
Annual Energy Profits Levy deferred adjustment	30	200	78
Accretion expense	44	37	27
Financing activities	(43)	(46)	(39)
Changes in valuation allowances	23	0	0
Non-taxable or non-deductible items:
Other adjustments	$ 0	$ 5	$ (40)
% of Income Before Income Taxes
Foreign tax effects	0.10%	(24.50%)	9.80%
Enacted changes in tax law	2.80%	0.00%	6.00%
Annual Energy Profits Levy deferred adjustment	1.10%	13.00%	2.70%
Accretion expense	0.016	0.024	0.009
Financing activities	(0.015)	(0.030)	(0.013)
Changes in valuation allowances	0.80%	0.00%	0.00%
Non-taxable or non-deductible items:
Other adjustments	0.00%	0.30%	(1.40%)
Suriname
Amount
Foreign tax effects	$ (5)	$ (13)	$ (8)
Changes in valuation allowances	(8)	18	10
Non-taxable or non-deductible items:
Other adjustments	$ 20	$ 13	$ 9
% of Income Before Income Taxes
Foreign tax effects	(0.20%)	(0.80%)	(0.30%)
Changes in valuation allowances	(0.30%)	1.20%	0.40%
Non-taxable or non-deductible items:
Other adjustments	0.70%	0.80%	0.30%
Other foreign jurisdictions
Amount
Foreign tax effects	$ 10	$ 9	$ 9
% of Income Before Income Taxes
Foreign tax effects	0.40%	0.60%	0.30%
United States
Amount
Changes in valuation allowances	$ (273)	$ 0	$ (1,852)
% of Income Before Income Taxes
Changes in valuation allowances	(9.80%)	0.00%	(64.20%)

STATEMENT OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interests	$ 1,692	$ 1,118	$ 3,207
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized derivative instrument (gains) losses, net	77	8	(51)
Gain on divestitures, net	(301)	(289)	(8)
Exploratory dry hole expense and unproved leasehold impairments	69	236	114
Depreciation, depletion, and amortization	2,304	2,266	1,540
Asset retirement obligation accretion	158	148	116
Impairments	44	1,129	61
Provision for (benefit from) deferred income taxes	360	(736)	(1,662)
Gain from extinguishment of debt	(147)	0	(9)
(Gains) losses on previously sold Gulf of America properties	(60)	273	212
Other	57	2	26
Changes in operating assets and liabilities:
Receivables	850	(104)	(157)
Inventories	7	(11)	13
Drilling advances and other current assets	223	(56)	269
Deferred charges and other long-term assets	36	11	270
Accounts payable	(365)	81	(84)
Accrued expenses	(199)	(221)	(400)
Deferred credits and noncurrent liabilities	(260)	(235)	(328)
NET CASH PROVIDED BY OPERATING ACTIVITIES	4,545	3,620	3,129
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,740)	(2,851)	(2,313)
Acquisition of Delaware Basin properties	0	0	(24)
Leasehold and property acquisitions	(26)	(60)	(20)
Proceeds from asset divestitures	611	1,609	29
Proceeds from sale of Kinetik shares	0	428	228
Other, net	2	(50)	(38)
NET CASH USED IN INVESTING ACTIVITIES	(2,153)	(924)	(2,138)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on commercial paper and revolving credit facilities, net	(333)	(40)	(194)
Proceeds from term loan facility	0	1,500	0
Payments on term loan facility	(900)	(600)	0
Payment on Callon Credit Agreement	0	(472)	0
Fixed rate debt borrowings	846	0	0
Payments on fixed-rate debt	(1,016)	(1,641)	(65)
Distributions to noncontrolling interest	(430)	(268)	(238)
Dividends paid to APA common stockholders	(360)	(353)	(308)
Treasury stock activity, net	(280)	(246)	(329)
Other, net	(28)	(38)	(15)
NET CASH USED IN FINANCING ACTIVITIES	(2,501)	(2,158)	(1,149)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(109)	538	(158)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	625	87	245
CASH AND CASH EQUIVALENTS AT END OF PERIOD	516	625	87
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	281	372	329
Income taxes paid, net of refunds	$ 999	$ 1,097	$ 1,271

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions.

Use of Estimates

Fair Value Measurements

Revenue Recognition

Refer to Note 16—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Payment Terms and Contract Balances

Cash and Cash Equivalents

Accounts Receivable and Allowance for Credit Losses

Inventories

Property and Equipment

Other Property and Equipment

Oil and Gas Property

The following table represents non-cash impairment charges of the carrying value of the Company’s proved and unproved properties:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Proved properties:
U.S.	$	—	$	315	$	—
Egypt	18		—		—
North Sea	—		796		—
Total proved properties	$	18	$	1,111	$	—

Unproved properties:
U.S.	$	—	$	34	$	10
Egypt	2		—		—
North Sea	—		—		11
Other International	—		1		1
Total unproved properties	$	2	$	35	$	22

For the year ended December 31, 2023, the Company recorded no impairments of proved properties.

Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction.

Gathering, Processing, and Transmission (GPT) Facilities

Asset Retirement Costs and Obligations

Capitalized Interest

Commitments and Contingencies

Derivative Instruments and Hedging Activities

Income Taxes

Earnings Per Share

Stock-Based Compensation

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

New Pronouncements Issued But Not Yet Adopted

INCOME TAXES - Net Deferred Tax Assets and Liabilities in the Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Deferred tax asset	$ 2,328	$ 2,703
Deferred tax liability	0	14
Net deferred income tax asset	$ (2,328)	$ (2,689)

ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2025 and 2024:


	For the Year Ended December 31,
	2025		2024

	(In millions)
Asset retirement obligation at beginning of the year	$	2,694	$	2,438
Liabilities incurred	23		15
Liabilities acquired	—		136
Liabilities divested	(8)		(272)
Liabilities settled	(100)		(70)
Accretion expense	158		148
Revisions in estimated liabilities	113		299

Asset retirement obligation at end of the year	2,880		2,694
Less current portion	(181)		(103)
Asset retirement obligation, long-term	$	2,699	$	2,591

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.

During 2025 and 2024, the Company recorded $23 million and $15 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2025 and 2024, net abandonment costs were revised upward by approximately $113 million and $299 million, respectively, primarily reflecting changes in estimates of timing and activity costs in the U.S. and North Sea, in addition to foreign currency exchange rates on service costs.

CAPITAL STOCK - Valuation Assumptions (Details)	12 Months Ended
CAPITAL STOCK - Valuation Assumptions (Details)	Dec. 31, 2025 $ / shares
Compensation Related Costs [Abstract]
Expected volatility	57.37%
Expected dividend yields	4.30%
Expected term	6 years
Risk-free rate	4.43%
Weighted-average grant-date fair value (in dollars per share)	$ 9.50

ASSET RETIREMENT OBLIGATION - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 23	$ 15
Revisions in estimated liabilities	$ 113	$ 299

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit loss at beginning of year	$ 123	$ 114	$ 117
Additional provisions for the year	20	9	16
Uncollectible accounts written off, net of recoveries	(3)	0	(19)
Allowance for credit loss at end of year	$ 140	$ 123	$ 114

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)		12 Months Ended
	Apr. 01, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule Of Significant Accounting Policies [Line Items]
Other asset impairments		$ 37,000,000		$ 11,000,000
Receivables from contracts with customers, net of allowance for doubtful accounts		826,000,000	$ 1,700,000,000
Cash and cash equivalent		516,000,000	625,000,000
Restricted cash		0	0
Inventory write-downs		7,000,000	18,000,000
Inventory and other, impairments				50,000,000
Gathering, processing, and transmission facilities		445,000,000	433,000,000
GPT facilities, accumulated depreciation		(383,000,000)	(364,000,000)
Other property and equipment		146,000,000	183,000,000
Transaction, reorganization, and separation		102,000,000	168,000,000	15,000,000
Ongoing consulting and separation costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation				7,000,000
Callon Petroleum Company
Schedule Of Significant Accounting Policies [Line Items]
Consideration transferred	$ 4,500,000,000
Transaction, reorganization, and separation			147,000,000
Callon Petroleum Company \| Separation Costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation			76,000,000
Callon Petroleum Company \| Transaction And Integration Costs
Schedule Of Significant Accounting Policies [Line Items]
Transaction, reorganization, and separation			71,000,000
Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		18,000,000	1,111,000,000	0
Oil and gas property impaired, fair value			263,000,000
Gathering, processing, and transmission facilities
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment		$ 1,000,000	0	0
Other Property and Equipment \| Minimum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities		3 years
Other Property and Equipment \| Maximum
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities		20 years
Office Building
Schedule Of Significant Accounting Policies [Line Items]
Tangible asset impairment		$ 18,000,000
United States
Schedule Of Significant Accounting Policies [Line Items]
Inventory write-downs			5,000,000
United States \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		0	315,000,000	0
Egypt \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		18,000,000	0	0
North Sea
Schedule Of Significant Accounting Policies [Line Items]
Inventory write-downs			13,000,000
North Sea \| Proved properties:
Schedule Of Significant Accounting Policies [Line Items]
Impairments		$ 0	$ 796,000,000	$ 0
Apache Egypt \| Sinopec
Schedule Of Significant Accounting Policies [Line Items]
Ownership percentage by noncontrolling owners		33.33%

CAPITAL STOCK - Performance Program Narrative (Details) - USD ($)	1 Months Ended				12 Months Ended
	Jan. 31, 2026	Jan. 31, 2025	Jan. 31, 2024	Jan. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jan. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)					5,200,000
Compensation expense					$ 107,000,000	$ 49,000,000	$ 84,000,000
Stock-settled and cash-settled compensation capitalized					$ 15,000,000	$ 9,000,000	$ 13,000,000
Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)					2,302,000	2,369,000	1,972,000
Phantom Units \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	2,115,116
Award, remeasurement basis (in shares)	1
Performance Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period					3 years
Compensation expense					$ 45,000,000	$ 13,000,000	$ 2,000,000
Stock-settled and cash-settled compensation capitalized					$ 3,000,000	$ 1,000,000	$ 100,000
Performance Program \| Vesting, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage					50.00%
Performance Program \| Vesting, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage					50.00%
2022 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)								1,093,034
Number of awards outstanding (in shares)					713,514
Shares paid out as percentage of target					118.00%
2023 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of awards authorized (in shares)				822,200
Number of awards outstanding (in shares)					636,488
Shares paid out as percentage of target					120.00%
2023 Performance Program \| Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target				0.00%
2023 Performance Program \| Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target				200.00%
2024 performance program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period					3 years
Number of awards outstanding (in shares)			645,318		468,708
Compensation expense					$ 11,000,000
2024 performance program \| Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			0.00%
Shares authorized and available for grant (in shares)					0
Compensation expense					$ 0
2024 performance program \| Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target			200.00%
Shares authorized and available for grant (in shares)					937,416
Compensation expense					$ 22,000,000
2025 Performance Program \| Phantom Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period					3 years
Number of awards authorized (in shares)		1,028,112
Number of awards outstanding (in shares)					871,793
Compensation expense					$ 14,000,000
2025 Performance Program \| Phantom Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		0.00%
Shares authorized and available for grant (in shares)					0
Compensation expense					$ 0
2025 Performance Program \| Phantom Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded as percentage of target		200.00%
Shares authorized and available for grant (in shares)					1,743,586
Compensation expense					$ 28,000,000
2026 Performance Program \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award performance period	3 years
Compensation expense	$ 14,000,000
Award, remeasurement basis (in shares)	1
2026 Performance Program \| Minimum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 0
2026 Performance Program \| Maximum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash incentive payout amount	$ 28,000,000
2026 Performance Program \| Phantom Units \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted during period (in shares)	904,442
2026 Performance Program \| Phantom Units \| Minimum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	0
2026 Performance Program \| Phantom Units \| Maximum \| Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant (in shares)	1,808,884

STATEMENT OF CONSOLIDATED OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
REVENUES AND OTHER:
Derivative instrument gains (losses), net	$ (53)	$ (10)	$ 99
Gain on divestitures, net	301	289	8
Gains (losses) on previously sold Gulf of America properties	60	(273)	(212)
Other, net	(8)	(6)	18
Total revenues and other	9,220	9,737	8,192
OPERATING EXPENSES:
Lease operating expenses	1,504	1,690	1,436
Taxes other than income	229	270	207
Exploration	131	313	195
General and administrative	350	372	351
Transaction, reorganization, and separation	102	168	15
Depreciation, depletion, and amortization	2,304	2,266	1,540
Asset retirement obligation accretion	158	148	116
Impairments	44	1,129	61
Financing costs, net	113	367	312
Total operating expenses	6,429	8,202	5,309
NET INCOME BEFORE INCOME TAXES	2,791	1,535	2,883
Current income tax provision	739	1,153	1,338
Deferred income tax provision (benefit)	360	(736)	(1,662)
NET INCOME INCLUDING NONCONTROLLING INTERESTS	1,692	1,118	3,207
Net income attributable to noncontrolling interest	258	314	352
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$ 1,434	$ 804	$ 2,855
NET INCOME PER COMMON SHARE:
Basic (in USD per share)	$ 3.99	$ 2.28	$ 9.26
Diluted (in USD per share)	$ 3.99	$ 2.27	$ 9.25
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	359	353	308
Diluted (in shares)	359	353	309
Oil and gas
REVENUES AND OTHER:
Total revenues	$ 8,920	$ 9,737	$ 8,279
Oil, natural gas, and natural gas liquids production revenues
REVENUES AND OTHER:
Total revenues	7,229	8,196	7,385
OPERATING EXPENSES:
Gathering, processing, and transmission & purchased oil and gas costs	424	432	334
Purchased oil and gas costs
REVENUES AND OTHER:
Total revenues	1,691	1,541	894
OPERATING EXPENSES:
Gathering, processing, and transmission & purchased oil and gas costs	$ 1,070	$ 1,047	$ 742

DEBT AND FINANCING COSTS

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

DEBT AND FINANCING COSTS

Overview

The debt of APA and Apache is senior unsecured debt and has equal priority with respect to the payment of both principal and interest.

The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations.

The following table presents the carrying value of the Company’s debt as of December 31, 2025 and 2024:


	December 31,
	2025		2024

	(In millions)

4.625% notes due 2025	$	—	$	51
7.70% notes due 2026(1)(3)	79		78
7.95% notes due 2026(1)(3)	132		132
4.875% notes due 2027(1)(2)	108		108
4.375% notes due 2028(1)(2)	315		325
7.75% notes due 2029(1)(3)(4)	232		235
4.250% notes due 2030(1)(2)	475		516
6.10% notes due 2035(2)	350		—
6.000% notes due 2037(1)(2)	433		443
5.100% notes due 2040(1)(2)	763		1,333
5.250% notes due 2042(1)(2)	244		399
4.750% notes due 2043(1)(2)	217		428
4.250% notes due 2044(1)(2)	100		211
7.375% debentures due 2047(1)(3)	150		150
5.350% notes due 2049(1)(2)	374		387
6.75% notes due 2055(2)	500		—
7.625% debentures due 2096(1)(3)	39		39
Notes and debentures before unamortized discount and debt issuance costs(5)(6)	4,511		4,835
Commercial paper	—		323
Term loan facility	—		900
Syndicated credit facilities(7)	—		10
Apache finance lease obligations	28		30
Unamortized discount	(23)		(25)
Debt issuance costs	(23)		(29)
Total debt	4,493		6,044
Current maturities	(213)		(53)
Long-term debt	$	4,280	$	5,991

(1)This series of indenture debt includes series separately issued by APA and by Apache (see “APA Exchange and Tender Offers for Apache Indenture Debt” in this Note 8 below). The indicated amount as of December 31, 2025 is an aggregate amount for APA and Apache debt of this series. The indicated amount as of December 31, 2024 is solely Apache debt of this series; there was no APA indenture debt outstanding on December 31, 2024.

(2)These notes are redeemable, in whole or in part, at the issuer’s option, subject to a make-whole premium.

(3)These notes and debentures are not redeemable, except that the 7.75% notes due 2029 for which Apache is obligated are redeemable in whole for principal and accrued interest in the event of certain Canadian tax law changes.

(4)Outstanding 7.75% notes due 2029 for which Apache is obligated were assumed by Apache in August 2017 as permitted by terms of such notes originally issued by a subsidiary and guaranteed by Apache.

(5)The aggregate amount as of December 31, 2025 is comprised of $3.6 billion for APA notes and debentures and $932 million for Apache notes and debentures. The aggregate amount as of December 31, 2024 is comprised solely of Apache indenture debt; there was no APA indenture debt on December 31, 2024.

(6)The fair values of the notes and debentures were $4.3 billion and $4.4 billion as of December 31, 2025 and 2024, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

(7)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2025 are as follows:


	(In millions)
2026	$	211
2027	108
2028	315
2029	232
2030	475
Thereafter	3,170
Notes and debentures, excluding discounts and debt issuance costs	$	4,511

Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Interest expense	$	323	$	402	$	351
Amortization of debt issuance costs	7		6		4
Capitalized interest	(45)		(29)		(24)
Gain on extinguishment of debt	(147)		—		(9)
Interest income	(25)		(12)		(10)
Financing costs, net	$	113	$	367	$	312

Indenture Debt Activity

On August 20, 2025, Apache redeemed the outstanding $51 million principal amount of 4.625% Notes due 2025, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.

During 2025, the Company purchased in the open market and had canceled indebtedness issued under indentures of APA and Apache in an aggregate principal amount of $122 million for an aggregate purchase price of $112 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $13 million. The Company recognized a $12 million gain on these repurchases. The repurchases were partially financed by APA’s borrowing under the Company’s commercial paper program. Refer to discussion of APA exchange and tender offers for Apache indenture debt below for further details regarding the gain on extinguishment of debt during the quarter ended March 31, 2025.

During 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

The indentures under which APA has issued senior notes and debentures restrict it from issuing or guaranteeing certain secured indebtedness, consolidating with or merging into another person, and transferring or leasing its properties and assets as an entirety or substantially as an entirety to any person. Indentures of APA and Apache do not contain prepayment obligations in the event of a decline in credit ratings. In connection with the transactions summarized below under “APA Exchange and Tender Offers for Apache Indenture Debt”, Apache’s indentures were amended on January 10, 2025 to remove certain restrictive and reporting covenants, except those applicable to certain notes maturing in 2026 and 2027.

APA Exchange and Tender Offers for Apache Indenture Debt

On January 10, 2025, the Company settled its private exchange and cash tender offers for certain notes and debentures issued by Apache under its indentures. The Company also then settled its private offering of new notes to fund in part its purchase of Apache notes in APA’s cash tender offers. In settling these offerings pursuant to their respective terms:

•APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes and debentures tendered and accepted in APA’s exchange offers, (ii) $203 million in exchange for Apache notes tendered in the cash tender offers in excess of the stated maximum purchase amount or series caps, and (iii) $850 million in the new notes offering, comprised of $350 million aggregate principal amount of APA’s 6.10% Notes due 2035 and $500 million aggregate principal amount of APA’s 6.75% Notes due 2055.

•In addition to issuing the APA notes in the exchange offers, APA paid a total of $2.5 million in cash as part of the exchange consideration.

•APA paid a total of $869 million in cash in the tender offers (comprised of tender offer consideration, exchange consideration for tendered notes exchanged, early participation premium, and accrued interest) for the aggregate $1 billion in principal amount of Apache notes tendered and accepted in the cash tender offers. The Company recognized a gain of $135 million on these purchases, including broker fees and loan costs.

•Net proceeds from the sale of the notes in APA’s new notes offering, after deducting the initial purchasers’ discounts and estimated offering expenses, were approximately $839 million and used to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.

•Each series of APA notes and debentures issued in settlement of the exchange and tender offers had the same interest rate, maturity date, and interest payment dates and the same optional redemption prices (if any) as the corresponding series of Apache notes and debentures for which they were exchanged.

•Each series of APA notes and debentures issued in settlement of the exchange and tender offers and new notes offering were fully and unconditionally guaranteed by Apache until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than $1 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.

•APA entered into two registration rights agreements pursuant to which APA agreed to register under the Securities Act of 1933, as amended, the notes and debentures that APA issued in the exchange and tender offers and new notes offering (collectively, the Unregistered Notes). On September 18, 2025, APA settled registered exchange offers for the Unregistered Notes, issuing registered notes and debentures in the same aggregate principal amount as the Unregistered Notes accepted for exchange and canceled and otherwise on terms substantially identical in all material respects to the applicable series of Unregistered Notes. Of the $3.6 billion aggregate principal amount of Unregistered Notes covered by the registered exchange offers, 99 percent was exchanged for registered notes and debentures, and the remaining Unregistered Notes remained outstanding.

Unsecured 2025 Committed Bank Credit Facilities

On January 15, 2025, the Company entered into two unsecured syndicated credit agreements for general corporate purposes:

•One agreement is denominated in US dollars (the 2025 USD Agreement) and provides for an unsecured five-year revolving credit facility for loans and letters of credit, with aggregate commitments of US$2.0 billion (including a letter of credit subfacility of up to US$750 million, of which US$250 million currently is committed). APA may increase commitments up to an aggregate US$2.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in January 2030, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the 2025 GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in January 2030, subject to the Company’s two, one-year extension options.

Apache guaranteed obligations under each of the 2025 USD Agreement and 2025 GBP Agreement (each, a 2025 Agreement) effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures first was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on May 16, 2025.

The 2025 Agreements replaced on substantially the same terms two syndicated credit agreements that the Company entered in April 2022, one of which was denominated in US dollars with aggregate commitments of US$1.8 billion (the 2022 USD Agreement) and second of which was denominated in pounds sterling with aggregate commitments of £1.5 billion (the 2022 GBP Agreement). On January 15, 2025, the Company terminated commitments under both the 2022 USD Agreement and 2022 GBP Agreement in connection with entry into the 2025 Agreements.

As of December 31, 2025, there were no borrowings or letters of credit outstanding under the 2025 USD Agreement and no borrowings and an aggregate £1.0 million in letters of credit outstanding under the 2025 GBP Agreement. As of December 31, 2024, there were $10 million of borrowings and no letters of credit outstanding under the 2022 USD Agreement and no borrowings and an aggregate £303 million in letters of credit outstanding under the 2022 GBP Agreement.

All borrowings under the 2025 USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin varying from 0.0% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.00% to 1.675% (Applicable Margin). All borrowings under the 2025 GBP Agreement bear interest with respect to any business day at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average with respect to such business day published by the Bank of England, plus the Applicable Margin.

Each 2025 Agreement also requires the borrower to pay quarterly (i) a facility fee on total commitments at a per annum rate that varies from 0.125% to 0.325% and (ii) a commission on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA (Long-Term Debt Rating). The current Base Rate Margin is 0.30%, the Applicable Margin is 1.30%, and the facility fee is 0.20%.

Borrowers under each 2025 Agreement, which include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default, such as:

•A financial covenant requires APA to maintain an adjusted debt-to-capital ratio of not greater than 65% at the end of any fiscal quarter.

•A negative covenant restricts the ability of APA and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with customary exceptions and exceptions for liens on subsidiary assets located outside of the U. S. and Canada; liens on assets also are permitted if debt secured thereby does not exceed 15% of APA’s consolidated net tangible assets.

•Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.

•Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.

The 2025 Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.

The Company was in compliance with the terms of the 2025 Agreements as of December 31, 2025.

Uncommitted Lines of Credit

Each of the Company and Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2025 and 2024, there were no outstanding borrowings under these facilities. As of December 31, 2025, there were £901 million and $10 million in letters of credit outstanding under these facilities. As of December 31, 2024, there were £640 million and $11 million in letters of credit outstanding under these facilities.

Commercial Paper Program

The Company has a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $2.0 billion outstanding at any time. The program was established in December 2023, and the maximum aggregate face amount of CP Notes issuable thereunder was increased to $2.0 billion from $1.8 billion on June 20, 2025. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company’s committed revolving credit facilities for general corporate purposes, which as of December 31, 2025, included the $2.0 billion 2025 USD Agreement.

Payment of CP Notes was unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures was less than US$1.0 billion, which occurred in May 2025, after which Apache’s guarantees were terminated in accordance with their terms on June 20, 2025.

The CP Notes are sold under customary market terms in the U.S. commercial paper market at a discount from par or at par and bear interest at rates determined at the time of issuance.

As of December 31, 2025, the Company had no CP Notes outstanding. As of December 31, 2024, the Company had $323 million in aggregate face amount of CP Notes outstanding, which was classified as long-term debt.

Unsecured Committed Term Loan Facility

On January 30, 2024, APA entered into a syndicated credit agreement providing for committed senior unsecured delayed-draw term loans to APA, the proceeds of which could be used to refinance certain indebtedness of Callon.

On April 1, 2024, APA acquired Callon and borrowed $1.5 billion under this credit agreement maturing April 1, 2027, of which $900 million remained outstanding as of December 31, 2024. APA fully prepaid this credit agreement on March 10, 2025. The repayment was partially financed with borrowings under APA’s 2025 USD Agreement and commercial paper program.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

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+ Details

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2025

Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]

ACQUISITIONS AND DIVESTITURES

2025 Activity

Leasehold and Property Acquisitions

During 2025, the Company completed leasehold acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $26 million.

During the third quarter of 2025, the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations.

U.S. Divestitures

During the second quarter of 2025, the Company completed the sale of all of its New Mexico Permian assets. The assets had a carrying value of $282 million and associated retirement obligation of $9 million, which were exchanged for total cash consideration of $571 million, inclusive of post-closing adjustments. The Company recognized a gain of $299 million in association with this sale. Proceeds from the transaction were used primarily for debt reduction.

2024 Activity

Callon Petroleum Company Acquisition

On April 1, 2024, APA completed its acquisition of Callon in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon’s debt. Subject to the terms of the merger agreement, each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.

Recording of Assets Acquired and Liabilities Assumed

The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The table below presents the finalized value of the assets acquired and liabilities assumed.


	(In millions)
Current assets	$	287
Property and equipment	4,502
Deferred tax asset	565
Other assets	12
Total assets acquired	$	5,366
Current liabilities	$	632
Long-term debt	2,113
Asset retirement obligation	136

Other long-term obligations	48
Total liabilities assumed	$	2,929
Net assets acquired	$	2,437

The following unaudited pro forma combined results for the years ended December 31, 2024 and 2023 reflect the consolidated results of operations of the Company as if the Callon acquisition had occurred on January 1, 2023. The unaudited pro forma information includes certain accounting adjustments for transaction costs, depreciation, depletion, and amortization expense, and estimated tax impacts of the pro forma adjustments.


	For the Year Ended December 31,
	2024		2023

	(In millions)
Revenues	$	10,300	$	10,578
Net income attributable to common stock	909		4,021
Net income per common share – basic	2.45		10.66
Net income per common share – diluted	2.45		10.63

From the date of the acquisition through December 31, 2024, revenues and net income attributable to common stockholders associated with Callon assets totaled $1.2 billion and $262 million, respectively.

The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated. The unaudited pro forma results are also not intended to be a projection of future results and do not include any future cost savings or other synergies that may result from the Callon acquisition or any estimated costs that have not yet been incurred.

Leasehold and Property Acquisitions

During 2024, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for aggregate cash consideration of approximately $60 million.

U.S. Divestitures

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. The Company recognized a $50 million loss during 2024 in association with this sale.

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. The Company recognized a gain of $321 million in association with this sale.

Additionally, the Company completed the sale of non-core assets and leasehold in multiple transactions for aggregate cash proceeds of $91 million, recognizing a gain of approximately $22 million upon closing of these transactions.

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. The effective date of the transaction was July 1, 2024. As a result of the transaction, the Company performed a fair value assessment of the associated assets and liabilities and recorded an impairment of $315 million to the carrying value of the associated oil and gas properties during the third quarter of 2024. During the fourth quarter of 2024, the Company recorded a loss of $5 million upon closing of the transaction.

Sale of Kinetik Shares

On March 18, 2024, the Company sold its remaining shares of Kinetik Holdings Inc. (Kinetik) Class A Common Stock (Kinetik Shares) for cash proceeds of $428 million.

The following table represents related party sales and costs associated with Kinetik, when the Company was considered to have had significant influence over Kinetik prior to the Company’s sale of its remaining Kinetik Shares and the resignation of the Company’s designated director from the Kinetik board of directors:


	For the Year Ended December 31,
	2024		2023

	(In millions)
Natural gas and NGLs sales	$	13	$	92
Purchased oil and gas sales	22		29
	$	35	$	121

Gathering, processing, and transmission costs	$	23	$	108
Purchased oil and gas costs	23		80
Lease operating expenses	2		7
	$	48	$	195

2023 Activity

Sale of Kinetik Shares

In December 2023, the Company sold 7.5 million of its Kinetik Shares for cash proceeds of $228 million.

Leasehold and Property Acquisitions

During 2023, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $20 million.

U.S. Divestitures

During 2023, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $29 million, recognizing an aggregate gain of approximately $8 million upon closing of these transactions.

INCOME TAXES - Schedule of Net Operating Losses (Details) $ in Millions	Dec. 31, 2025 USD ($)
U.S.
Schedule Of Income Tax [Line Items]
Net operating losses	$ 9,463
State
Schedule Of Income Tax [Line Items]
Net operating losses	6,523
Foreign
Schedule Of Income Tax [Line Items]
Net operating losses	$ 211

RETIREMENT AND DEFERRED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

RETIREMENT AND DEFERRED COMPENSATION PLANS

The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership of APA, immediate and full vesting occurs.

The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $44 million, $46 million, and $44 million for 2025, 2024, and 2023, respectively.

The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2025, 2024, and 2023, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.


	2025						2024						2023
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	107		$	15		$	118		$	15		$	108		$	15
Service cost	1			1			1			1			1			1
Interest cost	6			1			6			1			5			1
Foreign currency exchange rates	8			—			(2)			—			6			—
Actuarial losses (gains)	(1)			(1)			(11)			—			3			—
Plan curtailments	—			—			—			(1)			—			—
Benefits paid	(6)			(2)			(5)			(2)			(5)			(3)
Retiree contributions	—			1			—			1			—			1
Projected benefit obligation at end of year	115			15			107			15			118			15
Change in Plan Assets
Fair value of plan assets at beginning of year	136			—			150			—			137			—
Actual return (loss) on plan assets	5			—			(8)			—			8			—
Foreign currency exchange rates	10			—			(3)			—			8			—
Employer contributions	2			1			2			1			2			1

Benefits paid	(6)			(2)			(5)			(2)			(5)			(3)
Retiree contributions	—			1			—			1			—			2
Fair value of plan assets at end of year	147			—			136			—			150			—
Funded status at end of year	$	32		$	(15)		$	29		$	(15)		$	32		$	(15)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(1)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	32			(14)			29			(13)			32			(13)
	$	32		$	(15)		$	29		$	(15)		$	32		$	(15)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(18)		$	14		$	(16)		$	14		$	(12)		$	16

Weighted Average Assumptions used as of December 31
Discount rate	5.60		%	5.18		%	5.60		%	5.49		%	4.80		%	5.00		%
Salary increases	4.50		%	N/A			4.70		%	N/A			4.60		%	N/A
Expected return on assets	5.60		%	N/A			5.70		%	N/A			4.80		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			6.50		%	N/A			6.25		%
Ultimate in 2035	N/A			5.25		%	N/A			5.25		%	N/A			5.25		%

As of December 31, 2025, 2024, and 2023, the accumulated benefit obligation for the U.K. Pension Plan was $111 million, $102 million, and $112 million, respectively.

The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets under a cash flow driven investment strategy. The Company intends to invest in primarily low risk debt securities that will provide a reasonable rate of return focused on cash flow timing such that the benefits promised to members are provided when due. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of allocations for the Company's plan asset holdings are summarized below:


	Percentage of Plan Assets at Year-End
	2025		2024
Asset Category

Multi-asset credit	61	%	62	%
Nominal bonds	3	%	4	%
Inflation-linked bonds	36	%	33	%
Cash	—	%	1	%
Total	100	%	100	%

The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2025 and 2024 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets as follows:


	December 31,
	2025		2024

	(In millions)
Asset Category

Multi-asset credit	90		84
Nominal bonds	3		6
Inflation-linked bonds	53		45
Cash	1		1
Total	$	147	$	136

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 1.3 percent per year.

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31 as follows:


	2025						2024						2023
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	1		$	1		$	1		$	1		$	1		$	1
Interest cost	6			1			6			1			5			1
Expected return on assets	(8)			—			(7)			—			(7)			—
Amortization of actuarial gain	—			(2)			—			(2)			—			(2)
Curtailment gain	—			—			—			(1)			—			—

Net periodic benefit cost	$	(1)		$	—		$	—		$	(1)		$	(1)		$	—
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.60		%	5.49		%	4.80		%	5.00		%	5.00		%	5.29		%
Salary increases	4.70		%	N/A			4.60		%	N/A			4.70		%	N/A
Expected return on assets	5.70		%	N/A			4.80		%	N/A			4.70		%	N/A
Healthcare cost trend
Initial	N/A			6.50		%	N/A			6.25		%	N/A			6.50		%
Ultimate in 2032	N/A			5.25		%	N/A			5.25		%	N/A			5.25		%

The Company expects to contribute approximately $1 million to its pension plan and $1 million to its postretirement benefit plan in 2026. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits

	(In millions)
2026	$	5	$	1
2027	7		1
2028	7		1
2029	7		1
2030	7		1
Years 2031-2035	39		7

- Definition

The entire disclosure for retirement benefits.

+ References

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+ Details

CAPITALIZED EXPLORATORY WELL COSTS - Schedule of Capitalized Exploratory Well Costs, Roll Forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Capitalized Exploratory Well Cost [Roll Forward]
Capitalized well costs at beginning of year	$ 237	$ 586	$ 474
Additions pending determination of proved reserves	234	240	265
Reclassifications to proved properties	(118)	(506)	(135)
Charged to exploration expense	(15)	(83)	(18)
Capitalized well costs at end of year	$ 338	$ 237	$ 586

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2025

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of December 31:


	2025		2024

	(In millions)
Inventories	$	351	$	425
Drilling advances	93		184

Current decommissioning security for sold Gulf of America assets	19		157
Prepaid assets and other	80		54
Total Other current assets	$	543	$	820

DEBT AND FINANCING COSTS - Schedule of Components of Financing Costs, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Debt Disclosure [Abstract]
Interest expense	$ 323	$ 402	$ 351
Amortization of debt issuance costs	7	6	4
Capitalized interest	(45)	(29)	(24)
Gain on extinguishment of debt	(147)	0	(9)
Interest income	(25)	(12)	(10)
Financing costs, net	$ 113	$ 367	$ 312

ACQUISITIONS AND DIVESTITURES - Schedule of Equity Method Investment Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]
Lease operating expenses	$ 1,504	$ 1,690	$ 1,436
Total operating expenses	6,429	8,202	5,309
Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		35	121
Lease operating expenses		2	7
Total operating expenses		48	195
Natural gas and NGLs sales
Schedule of Equity Method Investments [Line Items]
Total revenues	7,229	8,196	7,385
Gathering, processing, and transmission & purchased oil and gas costs	424	432	334
Natural gas and NGLs sales \| Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		13	92
Gathering, processing, and transmission & purchased oil and gas costs		23	108
Purchased oil and gas costs
Schedule of Equity Method Investments [Line Items]
Total revenues	1,691	1,541	894
Gathering, processing, and transmission & purchased oil and gas costs	$ 1,070	1,047	742
Purchased oil and gas costs \| Kinetik
Schedule of Equity Method Investments [Line Items]
Total revenues		22	29
Gathering, processing, and transmission & purchased oil and gas costs		$ 23	$ 80

- Definition

The aggregate costs related to goods produced and sold and services rendered by an entity during the reporting period. This excludes costs incurred during the reporting period related to financial services rendered and other revenue generating activities.

+ References + Details

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

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-Subparagraph (SX 210.13-01(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-30

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 32: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

+ Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

OTHER CURRENT LIABILITIES

12 Months Ended

Dec. 31, 2025

Payables and Accruals [Abstract]

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities as of December 31:


	2025		2024

	(In millions)
Accrued operating expenses	$	129	$	204
Accrued exploration and development	289		460

Accrued compensation and benefits	265		223
Accrued interest	88		93
Accrued income taxes	112		221
Current asset retirement obligation	181		103
Current operating lease liability	97		118

Current decommissioning contingency for sold Gulf of America properties	99		88
Other	227		168
Total Other current liabilities	$	1,487	$	1,678

INCOME TAXES - Income Taxes Paid (Net of Refunds) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Schedule Of Income Taxes [Line Items]
U.S. Federal	$ 92
U.S. State and Local	(15)
Foreign:	922
Income taxes paid, net of refunds	999	$ 1,097	$ 1,271
Egypt
Schedule Of Income Taxes [Line Items]
Foreign:	650
U.K.:
Schedule Of Income Taxes [Line Items]
Foreign:	$ 272

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	$ 41,967	$ 45,585	$ 37,099
Production costs	(13,541)	(14,216)	(12,791)
Development costs	(9,531)	(9,275)	(5,934)
Income tax expense	(2,286)	(3,581)	(4,117)
Net cash flows	16,609	18,513	14,257
10 percent discount rate	(5,771)	(6,934)	(4,216)
Discounted future net cash flows	$ 10,838	11,579	10,041
Estimated future net cash flow before income tax expenses	10.00%
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum	$ 12,600	14,400	13,600
United States
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	25,957	27,534	21,417
Production costs	(9,192)	(9,665)	(8,328)
Development costs	(3,640)	(4,124)	(2,238)
Income tax expense	(587)	(921)	(949)
Net cash flows	12,538	12,824	9,902
10 percent discount rate	(4,563)	(4,317)	(3,749)
Discounted future net cash flows	7,975	8,507	6,153
Egypt
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	9,208	9,342	9,921
Production costs	(1,978)	(1,716)	(1,690)
Development costs	(1,477)	(1,517)	(1,235)
Income tax expense	(1,686)	(1,923)	(2,222)
Net cash flows	4,067	4,186	4,774
10 percent discount rate	(971)	(872)	(943)
Discounted future net cash flows	3,096	3,314	3,831
Egypt \| Noncontrolling interest - Egypt
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Discounted future net cash flows	1,000	1,100	1,300
North Sea
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	1,769	2,828	5,761
Production costs	(1,077)	(1,399)	(2,773)
Development costs	(2,756)	(2,538)	(2,461)
Income tax expense	565	85	(946)
Net cash flows	(1,499)	(1,024)	(419)
10 percent discount rate	630	535	476
Discounted future net cash flows			57
Discounted future net cash flows	(869)	(489)
Suriname
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Cash inflows	5,033	5,881	0
Production costs	(1,294)	(1,436)	0
Development costs	(1,658)	(1,096)	0
Income tax expense	(578)	(822)	0
Net cash flows	1,503	2,527	0
10 percent discount rate	(867)	(2,280)	0
Discounted future net cash flows	$ 636	$ 247	$ 0

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Components of Accumulated Other Comprehensive Income (loss)

Components of accumulated other comprehensive income include the following:


	As of December 31,
	2025		2024		2023

	(In millions)

Pension and postretirement benefit plan (Note 11)	$	10	$	12	$	15
Accumulated other comprehensive income	$	10	$	12	$	15

DEBT AND FINANCING COSTS -Unsecured 2025 Committed Bank Credit Facilities (Details) £ in Millions, $ in Millions	Jan. 15, 2025 USD ($) creditAgreement option	Dec. 31, 2025 USD ($)	Dec. 31, 2025 GBP (£)	Jan. 15, 2025 GBP (£) creditAgreement	Dec. 31, 2024 USD ($)	Dec. 31, 2024 GBP (£)	Apr. 30, 2022 USD ($) creditAgreement	Apr. 30, 2022 GBP (£) creditAgreement
APA Corp
Debt Instrument [Line Items]
Number of credit agreements \| creditAgreement	2			2
Syndicated credit facilities \| Revolving Credit Facility
Debt Instrument [Line Items]
Credit facility fee, percentage	0.20%
Debt covenant, adjusted debt-to-capital ratio	0.65			0.65
Debt covenant, debt secured as percentage of consolidated net tangible assets	15.00%			15.00%
Syndicated credit facilities \| Revolving Credit Facility \| Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.30%
Syndicated credit facilities \| Revolving Credit Facility \| SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.30%
Syndicated credit facilities \| Revolving Credit Facility \| Minimum
Debt Instrument [Line Items]
Credit facility fee, percentage	0.125%
Syndicated credit facilities \| Revolving Credit Facility \| Maximum
Debt Instrument [Line Items]
Credit facility fee, percentage	0.325%
Syndicated credit facilities \| Unsecured Debt
Debt Instrument [Line Items]
Number of credit agreements \| creditAgreement							2	2
Syndicated credit facilities \| Line of Credit \| Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit outstanding		$ 0			$ 10
USD Agreement \| Minimum \| Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.00%
USD Agreement \| Maximum \| Base Rate
Debt Instrument [Line Items]
Debt basis spread on variable rate	0.675%
USD Agreement \| Line of Credit
Debt Instrument [Line Items]
Number of credit agreements denominated in US dollars \| creditAgreement							1	1
Line of credit facility, committed amount							$ 1,800
Line of credit outstanding					10
USD Agreement \| Line of Credit \| Letter of Credit
Debt Instrument [Line Items]
Line of credit outstanding		$ 0
Credit outstanding amount					$ 0
GBP Agreement \| Line of Credit
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, committed amount \| £								£ 1,500.0
GBP Agreement \| Line of Credit \| APA Corp
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity \| £				£ 1,500.0
Debt extension term	1 year
GBP Agreement \| Line of Credit \| Letter of Credit
Debt Instrument [Line Items]
Credit outstanding amount \| £			£ 1.0			£ 303.0
GBP Agreement \| Line of Credit \| Letter of Credit \| APA Corp
Debt Instrument [Line Items]
Line of credit facility, number of extension options \| option	2
2025 USD Agreement \| Minimum \| SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.00%
2025 USD Agreement \| Maximum \| SOFR
Debt Instrument [Line Items]
Debt basis spread on variable rate	1.675%
2025 USD Agreement \| Line of Credit
Debt Instrument [Line Items]
Number of credit agreements denominated in US dollars \| creditAgreement	1			1
2025 USD Agreement \| Line of Credit \| APA Corp
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility maximum borrowing capacity	$ 2,000
Increase of committed amount	$ 2,500
Debt extension term	1 year
2025 USD Agreement \| Line of Credit \| Letter of Credit \| APA Corp
Debt Instrument [Line Items]
Line of credit facility maximum borrowing capacity	$ 750
Line of credit facility, current borrowing capacity	$ 250
Line of credit facility, number of extension options \| option	2
Delayed-Drawn Term Loan \| Unsecured Debt \| Apache Corp
Debt Instrument [Line Items]
Guaranteed obligations, maximum	$ 1,000

BUSINESS SEGMENT INFORMATION - Financial Segment Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	$ 24	$ (2)	$ 48
Revenues and realized gain on derivatives	8,951	9,739	8,327
Operating Expenses:
Lease operating expenses	1,504	1,690	1,436
Taxes other than income	229	270	207
Exploration	131	313	195
Depreciation, depletion, and amortization	2,304	2,266	1,540
Asset retirement obligation accretion	158	148	116
Impairments	44	1,129	61
Total operating expenses	5,864	7,295	4,631
Operating Income (Loss)	3,087	2,444	3,696
Other Income (Expense):
Gain on divestitures, net	301	289	8
Gains (losses) on previously sold Gulf of America properties	60	(273)	(212)
Unrealized losses on commodity derivative instruments	(77)	(8)	51
Other	(8)	(6)	18
General and administrative	(350)	(372)	(351)
Transaction, reorganization, and separation	(102)	(168)	(15)
Financing costs, net	(113)	(367)	(312)
NET INCOME BEFORE INCOME TAXES	2,791	1,535	2,883
Total Assets	17,761	19,390	15,244
Net Property and Equipment	12,748	12,646	10,038
Additions to Net Property and Equipment	2,673	7,499	2,313
Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	31	2	48
Contingent consideration arrangements
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	(7)	(4)	0
Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Revenues and realized gain on derivatives	5,541	5,858	3,960
Operating Expenses:
Lease operating expenses	724	820	593
Taxes other than income	229	270	207
Exploration	9	134	14
Depreciation, depletion, and amortization	1,434	1,340	745
Asset retirement obligation accretion	41	42	40
Impairments	18	320	11
Total operating expenses	3,871	4,327	2,601
Operating Income (Loss)	1,670	1,531	1,359
Other Income (Expense):
Total Assets	12,568	13,870	9,221
Net Property and Equipment	9,019	9,109	5,689
Additions to Net Property and Equipment	1,614	6,609	1,255
Operating Segments \| U.S. \| Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	31	2	48
Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Revenues and realized gain on derivatives	2,637	2,933	3,029
Operating Expenses:
Lease operating expenses	447	464	474
Taxes other than income	0	0	0
Exploration	101	112	119
Depreciation, depletion, and amortization	630	625	524
Asset retirement obligation accretion	0	0	0
Impairments	19	0	0
Total operating expenses	1,221	1,226	1,150
Operating Income (Loss)	1,416	1,707	1,879
Other Income (Expense):
Total Assets	3,055	3,606	3,503
Net Property and Equipment	2,306	2,271	2,209
Additions to Net Property and Equipment	747	765	834
Operating Segments \| Egypt \| Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	0	0	0
Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Revenues and realized gain on derivatives	773	948	1,338
Operating Expenses:
Lease operating expenses	333	406	369
Taxes other than income	0	0	0
Exploration	1	1	19
Depreciation, depletion, and amortization	240	301	271
Asset retirement obligation accretion	117	106	76
Impairments	7	809	50
Total operating expenses	752	1,676	837
Operating Income (Loss)	21	(728)	501
Other Income (Expense):
Total Assets	1,216	1,324	1,970
Net Property and Equipment	570	712	1,628
Additions to Net Property and Equipment	13	41	131
Operating Segments \| North Sea \| Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	0	0	0
Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues and realized gain on derivatives	0	0	0
Operating Expenses:
Lease operating expenses	0	0	0
Taxes other than income	0	0	0
Exploration	20	66	43
Depreciation, depletion, and amortization	0	0	0
Asset retirement obligation accretion	0	0	0
Impairments	0	0	0
Total operating expenses	20	66	43
Operating Income (Loss)	(20)	(66)	(43)
Other Income (Expense):
Total Assets	922	590	550
Net Property and Equipment	853	554	512
Additions to Net Property and Equipment	299	84	93
Intersegment Eliminations & Other \| Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments			0
Intersegment Eliminations & Other \| North Sea \| Commodity derivative instruments
Segment Reporting Information [Line Items]
Realized gains on commodity derivative instruments	0	0
Oil, natural gas, and natural gas liquids production revenues
Segment Reporting Information [Line Items]
Total revenues	7,229	8,196	7,385
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	424	432	334
Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Total revenues	3,819	4,315	3,018
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	346	354	249
Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Total revenues	2,637	2,933	3,029
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	24	25	33
Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Total revenues	773	948	1,338
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	54	53	52
Oil, natural gas, and natural gas liquids production revenues \| Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	0	0	0
Purchased oil and gas costs
Segment Reporting Information [Line Items]
Total revenues	1,691	1,541	894
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	1,070	1,047	742
Purchased oil and gas costs \| Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Total revenues	1,691	1,541	894
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	1,070	1,047	742
Purchased oil and gas costs \| Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	0	0	0
Purchased oil and gas costs \| Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	0	0	0
Purchased oil and gas costs \| Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Operating Expenses:
Gathering, processing, and transmission & purchased oil and gas costs	0	0	0
Oil revenues
Other Income (Expense):
Revenue from non-customers	536	686	729
Oil revenues \| Oil, natural gas, and natural gas liquids production revenues
Segment Reporting Information [Line Items]
Total revenues	5,809	6,966	5,997
Oil revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Total revenues	3,010	3,572	2,241
Oil revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Total revenues	2,177	2,620	2,683
Oil revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Total revenues	622	774	1,073
Oil revenues \| Oil, natural gas, and natural gas liquids production revenues \| Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Natural gas revenues
Other Income (Expense):
Revenue from non-customers	114	83	95
Natural gas revenues \| Oil, natural gas, and natural gas liquids production revenues
Segment Reporting Information [Line Items]
Total revenues	770	584	880
Natural gas revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Total revenues	193	126	297
Natural gas revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Total revenues	460	313	346
Natural gas revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Total revenues	117	145	237
Natural gas revenues \| Oil, natural gas, and natural gas liquids production revenues \| Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Natural gas liquids revenues \| Oil, natural gas, and natural gas liquids production revenues
Segment Reporting Information [Line Items]
Total revenues	650	646	508
Natural gas liquids revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| U.S.
Segment Reporting Information [Line Items]
Total revenues	616	617	480
Natural gas liquids revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| Egypt
Segment Reporting Information [Line Items]
Total revenues	0	0	0
Natural gas liquids revenues \| Oil, natural gas, and natural gas liquids production revenues \| Operating Segments \| North Sea
Segment Reporting Information [Line Items]
Total revenues	34	29	28
Natural gas liquids revenues \| Oil, natural gas, and natural gas liquids production revenues \| Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Total revenues	$ 0	$ 0	$ 0

INCOME TAXES

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

INCOME TAXES

Net income before income taxes was composed of the following:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
U.S.	$	1,488	$	705	$	627
Foreign	1,303		830		2,256
Total	$	2,791	$	1,535	$	2,883

The total income tax provision (benefit) consisted of the following:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Current income taxes:
Federal	$	(104)	$	76	$	2
State	(1)		2		6
Foreign	844		1,075		1,330
	739		1,153		1,338
Deferred income taxes:
Federal	384		(96)		(1,708)
State	41		3		(32)
Foreign	(65)		(643)		78
	360		(736)		(1,662)
Total	$	1,099	$	417	$	(324)

The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below:


	For the Year Ended December 31,
	2025				2024			2023

	Amount		% of Income Before Income Taxes			Amount		% of Income Before Income Taxes		Amount		% of Income Before Income Taxes
	(In millions)
U.S. federal statutory tax rate	$	586	21.0	%		$	322	21.0	%	$	605	21.0	%
State and local income taxes, net of federal income tax effect(1)	31		1.1	%		2		0.1	%	(23)		(0.8)	%
Foreign tax effects:
Egypt:
Statutory tax rate difference between Egypt and U.S.	277		9.9	%		334		21.8	%	366		12.7	%
Concessions on production-sharing contracts	75		2.8	%		77		5.0	%	65		2.3	%
U.K.:
Statutory tax rate difference between U.K. and U.S.	4		0.1	%		(376)		(24.5)	%	283		9.8	%
Enacted changes in tax law	78		2.8	%		—		—	%	174		6.0	%
Annual Energy Profits Levy deferred adjustment	30		1.1	%		200		13.0	%	78		2.7	%
Accretion expense	44		1.6	%		37		2.4	%	27		0.9	%
Financing activities	(43)		(1.5)	%		(46)		(3.0)	%	(39)		(1.3)	%
Changes in valuation allowances	23		0.8	%		—		—	%	—		—	%
Other	—		—	%		5		0.3	%	(40)		(1.4)	%
Suriname:
Statutory tax rate difference between Suriname and U.S.	(5)		(0.2)	%		(13)		(0.8)	%	(8)		(0.3)	%
Changes in valuation allowances	(8)		(0.3)	%		18		1.2	%	10		0.4	%
Other	20		0.7	%		13		0.8	%	9		0.3	%
Other foreign jurisdictions	10		0.4	%		9		0.6	%	9		0.3	%

Cross-border tax laws	1		—	%		1		0.1	%	1		—	%
Tax credits:
Corporate alternative minimum tax credit	71		2.5	%		(74)		(4.8)	%	—		—	%
Other tax credits	(1)		—	%		(3)		(0.2)	%	—		—	%
Foreign tax credits	269		9.6	%		—		—	%	—		—	%
Changes in valuation allowances	(273)		(9.8)	%		—		—	%	(1,852)		(64.2)	%
Non-taxable or non-deductible items:
Stock compensation	1		—	%		17		1.1	%	(2)		(0.1)	%
Legal reserves	—		—	%		14		0.9	%	—		—	%
Transaction costs	—		—	%		5		0.3	%	—		—	%
U.S tax basis of investment in U.K.	—		—	%		(214)		(13.9)	%	—		—	%
Other	(1)		—	%		10		0.7	%	8		0.3	%
Changes in unrecognized tax benefits	(16)		(0.6)	%		2		0.1	%	5		0.2	%
Other adjustments:
Corporate alternative minimum tax	(71)		(2.5)	%		74		4.8	%	—		—	%
Other adjustments	(3)		(0.1)	%		3		0.2	%	—		—	%
Total income tax provision (benefit)	$	1,099	39.4	%		$	417	27.2	%	$	(324)	(11.2)	%

(1)Taxes in Texas and New Mexico represented greater than 50 percent of the total state and local income tax effect.

The net deferred income tax asset reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax asset consisted of the following as of December 31:


	2025		2024

	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,298	$	2,487
Capital losses	13		14
Foreign net operating losses	76		55
Tax credits and other tax incentives	36		105
Foreign tax credits	1,935		2,204
Accrued expenses and liabilities	96		76
Asset retirement obligation	1,021		952
Property and equipment	16		45
Equity investments	1		1
Net interest expense limitation	130		287
Lease liability	93		114
Decommissioning contingency for sold Gulf of America properties	200		232
Other	51		—
Total deferred tax assets	5,966		6,572
Valuation allowance	(2,401)		(2,623)
Net deferred tax assets	3,565		3,949
Deferred tax liabilities:



Property and equipment	1,108		1,060
Right-of-use asset	87		111
Decommissioning security for sold Gulf of America properties	9		40
Other	33		49
Total deferred tax liabilities	1,237		1,260
Net deferred income tax asset	$	2,328	$	2,689

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:


	2025		2024

	(In millions)
Assets:
Other assets
Deferred tax asset	$	2,328	$	2,703
Liabilities:
Deferred credits and other noncurrent liabilities
Deferred tax liability	—		14
Net deferred income tax asset	$	2,328	$	2,689

On April 1, 2024, the Company completed its acquisition of Callon in an all-stock transaction. The Company’s deferred tax asset increased by approximately $565 million as part of the assets assumed through the Callon acquisition. Refer to Note 2— Acquisitions and Divestitures for further detail.

On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022 (the Energy Profits Levy), increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included further amendments to the Energy Profits Levy, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. As a result, the Company recorded tax expense of $78 million and $174 million related to the change in tax law in 2025 and 2023, respectively.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. In 2025, the Company recorded a current tax benefit of $71 million related to the 2024 return-to-accrual adjustment, with an offsetting deferred tax expense of the same amount for the change in CAMT credits.

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. OBBBA did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the law change resulted in a current tax benefit of $42 million fully offset by a deferred tax expense of the same amount.

On September 30, 2025, the Internal Revenue Service issued further interim guidance on CAMT. Among other changes, the guidance provided for a reduction to CAMT related to net operating loss utilization for regular federal income tax purposes. This guidance did not have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In 2025, the guidance resulted in a current tax benefit of $72 million, fully offset by a deferred tax expense of the same amount.

In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, the Company does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.

Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as net operating losses, tax credits and other tax attributes, provided that the Company assesses the utilization of such assets to be “more likely than not.” The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. Based on this assessment, the Company has recorded valuation allowances for certain net operating losses, foreign tax credits and capital loss carryforwards that it does not believe are more likely than not to be realized.

During the fourth quarter of 2023, as a result of increases in projections of future taxable income and the absence of objective negative evidence such as a cumulative loss in recent years, the Company determined there was sufficient positive evidence to release a majority of the U.S. valuation allowance, which resulted in a non-cash deferred income tax benefit of $1.7 billion.

In 2025, 2024, and 2023, the Company’s valuation allowance decreased by $222 million, $7 million and $2.3 billion, respectively, as detailed in the table below:


	2025		2024		2023

	(In millions)
Balance at beginning of year	$	2,623	$	2,630	$	4,918
State(1)	33		(51)		(63)
U.S.	(270)		26		(2,235)
Foreign	15		18		10

Balance at end of year	$	2,401	$	2,623	$	2,630

(1)Reported as a component of state income taxes.

On December 31, 2025, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

9,463

2029 - Indefinite

State

6,523

Various

Foreign

211

2026 - Indefinite

The Company has a U.S. net operating loss carryforward of $9.5 billion, which includes $2.1 billion of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has state net operating losses of $6.5 billion, foreign net operating losses of $211 million, and a net interest expense carryover of $607 million under Section 163(j) of the Code with indefinite carryover. The Company has recorded a valuation allowance against some of the U.S. net operating losses, the state net operating losses, the foreign net operating losses, and the U.S. capital loss because it is more likely than not that these net operating losses and the capital loss carryforward will not be realized. The Company believes it is more likely than not that the deferred tax assets related to the remaining U.S. net operating losses and the net interest expense carryover will be utilized prior to their expiration.

On December 31, 2025, the Company had foreign tax credits as follows:


	Amount		Expiration
	(In millions)
Foreign tax credits	$	1,935	2026

The Company has a $1.9 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2025		2024		2023

	(In millions)
Balance at beginning of year	$	89	$	93	$	89
Additions based on tax positions related to prior year	—		1		4

Reductions for tax positions of prior years	(25)		(5)		—
Balance at end of year	$	64	$	89	$	93

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During the year ended December 31, 2025, the Company recorded an income tax benefit of $8.2 million for interest and penalties. In each of the years ended December 31, 2024 and 2023, the Company recorded tax expense of $2 million, respectively, for interest and penalties. At December 31, 2025, 2024, and 2023, the Company had an accrued liability for interest and penalties of nil, $9 million, and $7 million, respectively.

Income taxes paid (net of refunds) for the year ended December 31, 2025 were as follows:


	Amount
	(In millions)
U.S. Federal	$	92
U.S. State and Local	(15)

Foreign:
Egypt	650
U.K.	272
Foreign subtotal	922
Total	$	999

The Company and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. The Company’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction


U.S.			2014
Egypt			2007
U.K.			2022

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

MAJOR CUSTOMERS	12 Months Ended
MAJOR CUSTOMERS	Dec. 31, 2025
Risks and Uncertainties [Abstract]
MAJOR CUSTOMERS	MAJOR CUSTOMERS The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2025, sales to EGPC in Egypt accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. During 2024 and 2023, sales to EGPC accounted for approximately 17 percent and 15 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs revenues. Management does not believe that the loss of any single customer would have a material adverse effect on the results of operations.

- Definition

The entire disclosure for any concentrations existing at the date of the financial statements that make an entity vulnerable to a reasonably possible, near-term, severe impact. This disclosure informs financial statement users about the general nature of the risk associated with the concentration, and may indicate the percentage of concentration risk as of the balance sheet date.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
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-Subparagraph (d)(3)
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+ Details

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities.


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions, except per boe)
2025
Oil and gas production revenues	$	3,819	$	2,637	$	773	$	—	$	7,229
Operating cost:
Depreciation, depletion, and amortization(2)	1,411		625		239		—		2,275
Asset retirement obligation accretion	41		—		117		—		158
Lease operating expenses	724		447		333		—		1,504
Gathering, processing, and transmission	346		24		54		—		424
Exploration expenses	9		101		1		20		131
Impairments related to oil and gas properties	—		18		—		—		18
Production taxes(3)	227		—		—		—		227
Income tax	234		640		23		—		897
	2,992		1,855		767		20		5,634
Results of operations	$	827	$	782	$	6	$	(20)	$	1,595
2024
Oil and gas production revenues	$	4,315	$	2,933	$	948	$	—	$	8,196
Operating cost:
Depreciation, depletion, and amortization(2)	1,314		621		300		—		2,235
Asset retirement obligation accretion	42		—		106		—		148
Lease operating expenses	820		464		406		—		1,690
Gathering, processing, and transmission	354		25		53		—		432
Exploration expenses	134		112		1		66		313
Impairments related to oil and gas properties	315		—		796		—		1,111
Production taxes(3)	268		—		—		—		268
Income tax	235		770		(536)		—		469
	3,482		1,992		1,126		66		6,666
Results of operations	$	833	$	941	$	(178)	$	(66)	$	1,530
2023
Oil and gas production revenues	$	3,018	$	3,029	$	1,338	$	—	$	7,385
Operating cost:
Depreciation, depletion, and amortization(2)	709		521		270		—		1,500
Asset retirement obligation accretion	40		—		76		—		116
Lease operating expenses	593		474		369		—		1,436
Gathering, processing, and transmission	249		33		52		—		334
Exploration expenses	14		119		19		43		195

Production taxes(3)	204		—		—		—		204
Income tax	254		828		414		—		1,496
	2,063		1,975		1,200		43		5,281
Results of operations	$	955	$	1,054	$	138	$	(43)	$	2,104

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 16—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 16—Business Segment Information.

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities


	United States		Egypt(2)		North Sea		Other International		Total(2)

	(In millions)
2025
Acquisitions	$	23	$	10	$	—	$	—	$	33


Exploration	76		244		1		31		352
Development	1,558		530		96		288		2,472
Costs incurred(1)	$	1,657	$	784	$	97	$	319	$	2,857
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	6	$	—	$	—	$	39	$	45
Asset retirement costs	51		—		84		—		135
2024
Acquisitions(3)	$	4,561	$	3	$	—	$	—	$	4,564


Exploration	150		227		1		61		439
Development	2,067		559		186		47		2,859
Costs incurred(1)	$	6,778	$	789	$	187	$	108	$	7,862
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	3	$	—	$	—	$	26	$	29
Asset retirement costs	171		—		145		—		316

2023
Acquisitions	$	21	$	4	$	—	$	—	$	25


Exploration	31		226		44		131		432
Development	1,148		646		468		—		2,262
Costs incurred(1)	$	1,200	$	876	$	512	$	131	$	2,719
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	24	$	24
Asset retirement costs	(4)		—		375		—		371

(2) Includes a noncontrolling interest in Egypt.
(3) Includes acquisitions of unproved properties of $955 million for the U.S. related to the Callon acquisition.

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions)
2025
Proved properties	$	19,690	$	14,724	$	9,757	$	721	$	44,892
Unproved properties	384		99		—		132		615
	20,074		14,823		9,757		853		45,507
Accumulated DD&A	(11,220)		(12,558)		(9,189)		—		(32,967)
	$	8,854	$	2,265	$	568	$	853	$	12,540

2024
Proved properties	$	19,246	$	14,458	$	9,661	$	434	$	43,799
Unproved properties	711		67		—		121		899
	19,957		14,525		9,661		555		44,698
Accumulated DD&A	(11,053)		(12,299)		(8,952)		—		(32,304)
	$	8,904	$	2,226	$	709	$	555	$	12,394

(1)Includes a noncontrolling interest in Egypt.

Oil and Gas Reserve Information

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, the Company uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.


	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Suriname	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2022	177,708	108,050	82,580	—	368,338
December 31, 2023	179,542	102,305	61,076	—	342,923
December 31, 2024	184,744	95,990	30,436	—	311,170
December 31, 2025	182,300	101,750	22,136	—	306,186
Proved undeveloped reserves:
December 31, 2022	22,239	8,557	2,873	—	33,669
December 31, 2023	30,948	5,254	—	—	36,202
December 31, 2024	107,283	7,621	—	73,637	188,541
December 31, 2025	121,079	7,578	—	73,789	202,446

Total proved reserves:
Balance December 31, 2022	199,947	116,607	85,453	—	402,007
Extensions, discoveries and other additions	43,613	12,979	301	—	56,893
Purchases of minerals in-place	20	—	—	—	20
Revisions of previous estimates	(3,520)	10,505	(12,002)	—	(5,017)
Production	(28,795)	(32,532)	(12,676)	—	(74,003)
Sales of minerals in-place	(775)	—	—	—	(775)
Balance December 31, 2023	210,490	107,559	61,076	—	379,125
Extensions, discoveries and other additions	100,778	18,115	—	73,637	192,530
Purchases of minerals in-place	124,112	—	—	—	124,112
Revisions of previous estimates	(9,642)	10,521	(21,000)	—	(20,121)
Production	(47,043)	(32,584)	(9,640)	—	(89,267)
Sales of minerals in-place	(86,668)	—	—	—	(86,668)
Balance December 31, 2024	292,027	103,611	30,436	73,637	499,711
Extensions, discoveries and other additions	39,804	17,646	—	—	57,450

Revisions of previous estimates	24,942	20,088	528	152	45,710
Production	(45,817)	(32,017)	(8,828)	—	(86,662)
Sales of minerals in-place	(7,577)	—	—	—	(7,577)
Balance December 31, 2025	303,379	109,328	22,136	73,789	508,632

(1)Includes proved reserves of 36 MMbbls, 35 MMbbls, 36 MMbbls, and 39 MMbbls as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas Liquids
	United States	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2022	158,745	2,230	160,975
December 31, 2023	153,486	1,460	154,946
December 31, 2024	153,523	744	154,267
December 31, 2025	180,690	899	181,589
Proved undeveloped reserves:
December 31, 2022	19,004	76	19,080
December 31, 2023	18,401	—	18,401
December 31, 2024	54,674	—	54,674
December 31, 2025	58,438	—	58,438

Total proved reserves:
Balance December 31, 2022	177,749	2,306	180,055
Extensions, discoveries and other additions	25,711	371	26,082
Purchases of minerals in-place	21	—	21
Revisions of previous estimates	(8,568)	(764)	(9,332)
Production	(22,993)	(453)	(23,446)
Sales of minerals in-place	(33)	—	(33)
Balance December 31, 2023	171,887	1,460	173,347
Extensions, discoveries and other additions	62,988	—	62,988
Purchases of minerals in-place	51,406	—	51,406
Revisions of previous estimates	(20,167)	(277)	(20,444)
Production	(27,039)	(439)	(27,478)
Sales of minerals in-place	(30,878)	—	(30,878)
Balance December 31, 2024	208,197	744	208,941
Extensions, discoveries and other additions	16,232	—	16,232

Revisions of previous estimates	47,852	614	48,466
Production	(27,836)	(459)	(28,295)
Sales of minerals in-place	(5,317)	—	(5,317)
Balance December 31, 2025	239,128	899	240,027


	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)

	(Millions of cubic feet)
Proved developed reserves:
December 31, 2022	1,166,218	399,502	66,292	1,632,012
December 31, 2023	1,003,956	377,144	46,839	1,427,939
December 31, 2024	866,460	332,905	28,028	1,227,393
December 31, 2025	1,095,395	371,335	12,741	1,479,471
Proved undeveloped reserves:
December 31, 2022	210,862	1,068	2,304	214,234
December 31, 2023	99,495	2,612	—	102,107
December 31, 2024	307,775	27,499	—	335,274
December 31, 2025	338,100	27,780	—	365,880

Total proved reserves:
Balance December 31, 2022	1,377,080	400,570	68,596	1,846,246
Extensions, discoveries and other additions	158,118	14,188	3,335	175,641
Purchases of minerals in-place	136	—	—	136
Revisions of previous estimates	(266,664)	83,907	(6,739)	(189,496)
Production	(165,083)	(118,909)	(18,353)	(302,345)
Sales of minerals in-place	(136)	—	—	(136)
Balance December 31, 2023	1,103,451	379,756	46,839	1,530,046
Extensions, discoveries and other additions	354,267	60,366	—	414,633
Purchases of minerals in-place	279,615	—	—	279,615
Revisions of previous estimates	(224,118)	26,792	(4,176)	(201,502)
Production	(176,941)	(106,510)	(14,635)	(298,086)
Sales of minerals in-place	(162,039)	—	—	(162,039)
Balance December 31, 2024	1,174,235	360,404	28,028	1,562,667
Extensions, discoveries and other additions	95,264	65,514	—	160,778

Revisions of previous estimates	386,166	101,230	(3,856)	483,540
Production	(187,793)	(128,033)	(11,431)	(327,257)
Sales of minerals in-place	(34,377)	—	—	(34,377)
Balance December 31, 2025	1,433,495	399,115	12,741	1,845,351

(1) Includes proved reserves of 133 Bcf, 120 Bcf, 127 Bcf, and 134 Bcf as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.


	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Suriname	Total(1)

	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2022	530,823	174,633	95,859	—	801,315
December 31, 2023	500,354	165,162	70,343	—	735,859
December 31, 2024	482,677	151,474	35,852	—	670,003
December 31, 2025	545,555	163,639	25,159	—	734,353
Proved undeveloped reserves:
December 31, 2022	76,386	8,735	3,333	—	88,454
December 31, 2023	65,931	5,690	—	—	71,621
December 31, 2024	213,253	12,204	—	73,637	299,094
December 31, 2025	235,867	12,208	—	73,789	321,864

Total proved reserves:
Balance December 31, 2022	607,209	183,368	99,192	—	889,769
Extensions, discoveries and other additions	95,677	15,344	1,228	—	112,249
Purchases of minerals in-place	64	—	—	—	64
Revisions of previous estimates	(56,532)	24,490	(13,889)	—	(45,931)
Production	(79,302)	(52,350)	(16,188)	—	(147,840)
Sales of minerals in-place	(831)	—	—	—	(831)
Balance December 31, 2023	566,285	170,852	70,343	—	807,480
Extensions, discoveries and other additions	222,811	28,176	—	73,637	324,624
Purchases of minerals in-place	222,121	—	—	—	222,121
Revisions of previous estimates	(67,162)	14,986	(21,973)	—	(74,149)
Production	(103,572)	(50,336)	(12,518)	—	(166,426)
Sales of minerals in-place	(144,553)	—	—	—	(144,553)
Balance December 31, 2024	695,930	163,678	35,852	73,637	969,097
Extensions, discoveries and other additions	71,913	28,565	—	—	100,478

Revisions of previous estimates	137,155	36,960	499	152	174,766
Production	(104,952)	(53,356)	(11,192)	—	(169,500)
Sales of minerals in-place	(18,624)	—	—	—	(18,624)
Balance December 31, 2025	781,422	175,847	25,159	73,789	1,056,217

(1) Includes total proved reserves of 59 MMboe, 55 MMboe, 57 MMboe, and 61 MMboe as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.

During 2025, the Company added approximately 100 MMboe from extensions, discoveries, and other additions. The Company recorded 72 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin primarily focused on the Spraberry, Bone Spring, and Wolfcamp producing horizons. International operations contributed 28 MMboe of exploration and development additions occurring in Egypt primarily from gas-focused onshore exploration and appraisal.

The Company realized combined upward revision of previously estimated reserves of 175 MMboe. Upward revisions related to pricing and interest totaled 37 MMboe, driven primarily by an increase in Permian Basin gas pricing. Engineering and well performance adjustments totaled 138 MMboe in the U.S. and Egypt. Upward revisions of 100 MMboe in the U.S. is related to changes to development plans and updates due to reservoir performance. Egypt realized positive revisions of 38 MMboe from gas infrastructure optimization and improved recovery projects.

During 2024, the Company added approximately 325 MMboe from extensions, discoveries, and other additions. The Company recorded 223 MMboe of exploration and development adds in the U.S., derived from drilling activity in the Permian Basin targeting the Wolfcamp, Bone Spring and Spraberry producing horizons. International operations contributed 102 MMboe of exploration and development adds, with Egypt contributing 28 MMboe from onshore exploration and appraisal and 74 MMboe from the Suriname final investment decision.

During 2023, the Company added approximately 112 MMboe from extensions, discoveries, and other additions. The Company recorded 96 MMboe of exploration and development adds in the U.S., comprising 67 MMboe in the Permian Basin, 27 MMboe in the Delaware Basin, and 2 MMboe in the Texas Gulf Coast. Drilling programs for the Permian and Delaware Basins include the Wolfcamp, Bone Spring and Spraberry with the Austin Chalk as the primary focus for the Texas Gulf Coast. International operations contributed 16 MMboe of exploration and development adds, with Egypt contributing 15 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and 1 MMboe from the North Sea. The Company had combined downward revisions of previously estimated reserves of 46 MMboe, primarily driven by revisions in the U.S. Downward revisions for price and interest changes accounted for 83 MMboe, partially offset by engineering and performance upward revisions of 37 MMboe.

Approximately 8 percent of the Company’s year-end 2025 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 16, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2025, 2024, and 2023 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Future development costs include abandonment and dismantlement costs.

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under laws in effect as of December 31, 2025, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.


	United States		Egypt(1)		North Sea		Suriname		Total(1)

	(In millions)
2025
Cash inflows	$	25,957	$	9,208	$	1,769	$	5,033	$	41,967
Production costs	(9,192)		(1,978)		(1,077)		(1,294)		(13,541)
Development costs	(3,640)		(1,477)		(2,756)		(1,658)		(9,531)
Income tax expense	(587)		(1,686)		565		(578)		(2,286)
Net cash flows	12,538		4,067		(1,499)		1,503		16,609
10 percent discount rate	(4,563)		(971)		630		(867)		(5,771)
Discounted future net cash flows(2)	$	7,975	$	3,096	$	(869)	$	636	$	10,838
2024
Cash inflows	$	27,534	$	9,342	$	2,828	$	5,881	$	45,585
Production costs	(9,665)		(1,716)		(1,399)		(1,436)		(14,216)
Development costs	(4,124)		(1,517)		(2,538)		(1,096)		(9,275)
Income tax expense	(921)		(1,923)		85		(822)		(3,581)
Net cash flows	12,824		4,186		(1,024)		2,527		18,513
10 percent discount rate	(4,317)		(872)		535		(2,280)		(6,934)
Discounted future net cash flows(2)	$	8,507	$	3,314	$	(489)	$	247	$	11,579
2023
Cash inflows	$	21,417	$	9,921	$	5,761	$	—	$	37,099
Production costs	(8,328)		(1,690)		(2,773)		—		(12,791)
Development costs	(2,238)		(1,235)		(2,461)		—		(5,934)
Income tax expense	(949)		(2,222)		(946)		—		(4,117)
Net cash flows	9,902		4,774		(419)		—		14,257
10 percent discount rate	(3,749)		(943)		476		—		(4,216)
Discounted future net cash flows(2)	$	6,153	$	3,831	$	57	$	—	$	10,041

(1)Includes discounted future net cash flows of approximately $1.0 billion, $1.1 billion, and $1.3 billion as of December 31, 2025, 2024, and 2023, respectively, attributable to a noncontrolling interest in Egypt.

(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $12.6 billion, $14.4 billion, and $13.6 billion as of December 31, 2025, 2024, and 2023, respectively.

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Sales, net of production costs	$	(5,073)	$	(5,806)	$	(5,408)
Net change in prices and production costs	(2,859)		269		(7,089)
Discoveries and improved recovery, net of related costs	762		3,557		1,869
Change in future development costs	(993)		(695)		(413)
Previously estimated development costs incurred during the period	1,592		793		825
Revision of quantities	3,718		(428)		(262)
Purchases of minerals in-place	—		4,166		1
Accretion of discount	1,438		1,357		2,260
Change in income taxes	999		737		1,467
Sales of minerals in-place	(312)		(1,865)		(18)
Change in production rates and other	(13)		(547)		(793)
	$	(741)	$	1,538	$	(7,561)

- Definition

The entire disclosure for oil- and gas-producing activities considered to be supplementary information. Includes, but is not limited to, proved reserve quantity, cost incurred and capitalized, result of operation, standardized measure, and change in standardized measure of discounted future cash flow.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478688/932-270-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147477215/932-235-50-5

+ Details

ACQUISITIONS AND DIVESTITURES - 2025 Activity (Details) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2025 USD ($) acre	Jun. 30, 2025 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Business Combination [Line Items]
Payments to acquire leasehold and property			$ 26	$ 60	$ 20
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Combination [Line Items]
Gain (loss) on sale of oil and gas properties				$ 22	$ 8
Egypt
Business Combination [Line Items]
Number of awarded exploration acres \| acre	2,000,000
Signature bonus from government	$ 25
NEW MEXICO \| Disposed of by Sale \| Non-Core Assets And Leasehold
Business Combination [Line Items]
Carrying value of non-core assets disposed		$ 282
Asset retirement obligation assumed		9
Total cash consideration		571
Gain (loss) on sale of oil and gas properties		$ 299

OTHER CURRENT LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Payables and Accruals [Abstract]
Accrued operating expenses	$ 129	$ 204
Accrued exploration and development	289	460
Accrued compensation and benefits	265	223
Accrued interest	88	93
Accrued income taxes	112	221
Current asset retirement obligation	181	103
Current operating lease liability	97	118
Current decommissioning contingency for sold Gulf of America properties	99	88
Other	227	168
Total Other current liabilities	$ 1,487	$ 1,678

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Activities Recorded in the Statement of Consolidated Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	$ 24	$ (2)	$ 48
Unrealized gains (losses), net	(77)	(8)	51
Derivative instrument gains (losses), net	(53)	(10)	99
Commodity derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	31	2	48
Unrealized gains (losses), net	(77)	(6)	51
Contingent consideration arrangements
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses), net	(7)	(4)	0
Unrealized gains (losses), net	$ 0	$ (2)	$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
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-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4A

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Name Accounting Standards Codification
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-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CC

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Name Accounting Standards Codification
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-Subparagraph (f)
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-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (c)
-Publisher FASB
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Name Accounting Standards Codification
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4E

+ Details

- Definition

The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of derivative instruments, including options, swaps, futures, and forward contracts, held at each balance sheet date, that was included in earnings for the period.

+ References + Details

DEBT AND FINANCING COSTS - Schedule of Maturities of Long-Term Debt (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Disclosure [Abstract]
2026	$ 211
2027	108
2028	315
2029	232
2030	475
Thereafter	3,170
Notes and debentures, excluding discounts and debt issuance costs	$ 4,511

BUSINESS SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
	Dec. 31, 2025 segment
Segment Reporting [Abstract]
Number of operating segments	4
Number of reportable segments	4

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Net Income Before Income Taxes

Net income before income taxes was composed of the following:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
U.S.	$	1,488	$	705	$	627
Foreign	1,303		830		2,256
Total	$	2,791	$	1,535	$	2,883

Schedule of Total Provision for Income Taxes

The total income tax provision (benefit) consisted of the following:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Current income taxes:
Federal	$	(104)	$	76	$	2
State	(1)		2		6
Foreign	844		1,075		1,330
	739		1,153		1,338
Deferred income taxes:
Federal	384		(96)		(1,708)
State	41		3		(32)
Foreign	(65)		(643)		78
	360		(736)		(1,662)
Total	$	1,099	$	417	$	(324)

Schedule of Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense

A reconciliation of the tax on the Company’s net income before income taxes and total income tax provision (benefit) is shown below:


	For the Year Ended December 31,
	2025				2024			2023

	Amount		% of Income Before Income Taxes			Amount		% of Income Before Income Taxes		Amount		% of Income Before Income Taxes
	(In millions)
U.S. federal statutory tax rate	$	586	21.0	%		$	322	21.0	%	$	605	21.0	%
State and local income taxes, net of federal income tax effect(1)	31		1.1	%		2		0.1	%	(23)		(0.8)	%
Foreign tax effects:
Egypt:
Statutory tax rate difference between Egypt and U.S.	277		9.9	%		334		21.8	%	366		12.7	%
Concessions on production-sharing contracts	75		2.8	%		77		5.0	%	65		2.3	%
U.K.:
Statutory tax rate difference between U.K. and U.S.	4		0.1	%		(376)		(24.5)	%	283		9.8	%
Enacted changes in tax law	78		2.8	%		—		—	%	174		6.0	%
Annual Energy Profits Levy deferred adjustment	30		1.1	%		200		13.0	%	78		2.7	%
Accretion expense	44		1.6	%		37		2.4	%	27		0.9	%
Financing activities	(43)		(1.5)	%		(46)		(3.0)	%	(39)		(1.3)	%
Changes in valuation allowances	23		0.8	%		—		—	%	—		—	%
Other	—		—	%		5		0.3	%	(40)		(1.4)	%
Suriname:
Statutory tax rate difference between Suriname and U.S.	(5)		(0.2)	%		(13)		(0.8)	%	(8)		(0.3)	%
Changes in valuation allowances	(8)		(0.3)	%		18		1.2	%	10		0.4	%
Other	20		0.7	%		13		0.8	%	9		0.3	%
Other foreign jurisdictions	10		0.4	%		9		0.6	%	9		0.3	%

Cross-border tax laws	1		—	%		1		0.1	%	1		—	%
Tax credits:
Corporate alternative minimum tax credit	71		2.5	%		(74)		(4.8)	%	—		—	%
Other tax credits	(1)		—	%		(3)		(0.2)	%	—		—	%
Foreign tax credits	269		9.6	%		—		—	%	—		—	%
Changes in valuation allowances	(273)		(9.8)	%		—		—	%	(1,852)		(64.2)	%
Non-taxable or non-deductible items:
Stock compensation	1		—	%		17		1.1	%	(2)		(0.1)	%
Legal reserves	—		—	%		14		0.9	%	—		—	%
Transaction costs	—		—	%		5		0.3	%	—		—	%
U.S tax basis of investment in U.K.	—		—	%		(214)		(13.9)	%	—		—	%
Other	(1)		—	%		10		0.7	%	8		0.3	%
Changes in unrecognized tax benefits	(16)		(0.6)	%		2		0.1	%	5		0.2	%
Other adjustments:
Corporate alternative minimum tax	(71)		(2.5)	%		74		4.8	%	—		—	%
Other adjustments	(3)		(0.1)	%		3		0.2	%	—		—	%
Total income tax provision (benefit)	$	1,099	39.4	%		$	417	27.2	%	$	(324)	(11.2)	%

(1)Taxes in Texas and New Mexico represented greater than 50 percent of the total state and local income tax effect.

Schedule of Net Deferred Tax (Asset) Liability

The net deferred income tax asset consisted of the following as of December 31:


	2025		2024

	(In millions)
Deferred tax assets:

U.S. and state net operating losses	$	2,298	$	2,487
Capital losses	13		14
Foreign net operating losses	76		55
Tax credits and other tax incentives	36		105
Foreign tax credits	1,935		2,204
Accrued expenses and liabilities	96		76
Asset retirement obligation	1,021		952
Property and equipment	16		45
Equity investments	1		1
Net interest expense limitation	130		287
Lease liability	93		114
Decommissioning contingency for sold Gulf of America properties	200		232
Other	51		—
Total deferred tax assets	5,966		6,572
Valuation allowance	(2,401)		(2,623)
Net deferred tax assets	3,565		3,949
Deferred tax liabilities:



Property and equipment	1,108		1,060
Right-of-use asset	87		111
Decommissioning security for sold Gulf of America properties	9		40
Other	33		49
Total deferred tax liabilities	1,237		1,260
Net deferred income tax asset	$	2,328	$	2,689

Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:


	2025		2024

	(In millions)
Assets:
Other assets
Deferred tax asset	$	2,328	$	2,703
Liabilities:
Deferred credits and other noncurrent liabilities
Deferred tax liability	—		14
Net deferred income tax asset	$	2,328	$	2,689

Schedule of Valuation Allowance

In 2025, 2024, and 2023, the Company’s valuation allowance decreased by $222 million, $7 million and $2.3 billion, respectively, as detailed in the table below:


	2025		2024		2023

	(In millions)
Balance at beginning of year	$	2,623	$	2,630	$	4,918
State(1)	33		(51)		(63)
U.S.	(270)		26		(2,235)
Foreign	15		18		10

Balance at end of year	$	2,401	$	2,623	$	2,630

(1)Reported as a component of state income taxes.

Schedule of Net Operating Losses

On December 31, 2025, the Company had net operating losses as follows:

Amount

Expiration

(In millions)

U.S.

9,463

2029 - Indefinite

State

6,523

Various

Foreign

211

2026 - Indefinite

Schedule of Foreign Tax Credit Carryforward

On December 31, 2025, the Company had foreign tax credits as follows:


	Amount		Expiration
	(In millions)
Foreign tax credits	$	1,935	2026

Schedule of Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2025		2024		2023

	(In millions)
Balance at beginning of year	$	89	$	93	$	89
Additions based on tax positions related to prior year	—		1		4

Reductions for tax positions of prior years	(25)		(5)		—
Balance at end of year	$	64	$	89	$	93

Schedule of Cash Flow, Supplemental Disclosures

Income taxes paid (net of refunds) for the year ended December 31, 2025 were as follows:


	Amount
	(In millions)
U.S. Federal	$	92
U.S. State and Local	(15)

Foreign:
Egypt	650
U.K.	272
Foreign subtotal	922
Total	$	999

Schedule of Key Jurisdictions of Company's Earliest Open Tax Years

The Company’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction


U.S.			2014
Egypt			2007
U.K.			2022

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Inventories	$ 351	$ 425
Drilling advances	93	184
Current decommissioning security for sold Gulf of America assets	19	157
Prepaid assets and other	80	54
Total Other current assets	$ 543	$ 820

INCOME TAXES - Schedule of Valuation Allowance Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Balance at beginning of year	$ 2,623.0	$ 2,630.0	$ 4,918.0
Increase (decrease) of valuation allowances	(222.0)	(7.0)	(2,300.0)
Balance at end of year	2,401.0	2,623.0	2,630.0
State
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	33.0	(51.0)	(63.0)
U.S.
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	(270.0)	26.0	(2,235.0)
Foreign
Movement in Valuation Allowance of Deferred Tax Assets [Roll Forward]
Increase (decrease) of valuation allowances	$ 15.0	$ 18.0	$ 10.0

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Houston, Texas
Auditor Firm ID	42

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	The Company maintains a cybersecurity program that establishes safeguards for protecting the confidentiality, integrity, and availability of the Company’s data, technology, and information systems, and the material risks associated with the threats identified from time to time under the cybersecurity program are incorporated into the Company’s corporate risk register. The program includes general controls for managing changes in and access to the Company’s information technology environment, cybersecurity awareness and training programs to help employees identify and mitigate against cybersecurity threats, cybersecurity incident response plans and third-party incident response retainers to help expedite the Company’s response in the event of a cybersecurity incident, and guidelines regarding system vulnerability management, third-party threat intelligence, endpoint detection and response solutions, and network security measures. The program also establishes protocols for identifying and managing material risks related to cybersecurity threats associated with the Company’s use of third-party service providers. The Company monitors and oversees the material risks related to vulnerabilities, threats, and incidents impacting its third-party service providers via onboarding reviews, threat intelligence reports, and annual assessments. As an example of the Company’s efforts to manage third-party cybersecurity risks, when third parties are engaged to provide software-as-a-service offerings, the Company’s standard licensing terms require such third parties to utilize safeguards to protect the Company’s data, in compliance with applicable standards from the International Organization for Standardization (ISO) regarding security techniques, and to notify the Company within 24 hours of becoming aware of a cybersecurity incident impacting the Company’s data.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	The Company maintains a cybersecurity program that establishes safeguards for protecting the confidentiality, integrity, and availability of the Company’s data, technology, and information systems, and the material risks associated with the threats identified from time to time under the cybersecurity program are incorporated into the Company’s corporate risk register.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The standing Cybersecurity Committee of the Company’s Board of Directors assists with oversight of the Company’s cybersecurity program and the material risks associated with the threats identified under the program. Given the Cybersecurity Committee’s chair’s previous military experience in positions relevant to information security and his NACD-sponsored CERT Certificate in Cybersecurity Oversight from Carnegie Mellon University’s Software Engineering Institute, the committee benefits from his perspectives, skills, and training when reviewing and managing the Company’s exposure to cybersecurity risks.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The standing Cybersecurity Committee of the Company’s Board of Directors assists with oversight of the Company’s cybersecurity program and the material risks associated with the threats identified under the program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Board of Directors
Cybersecurity Risk Role of Management [Text Block]	The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee’s discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company’s internal control over financial reporting. APA’s Executive Vice President, Administration, is primarily responsible for identifying, assessing, and managing the material risks associated with cybersecurity threats and the incidents identified from time to time thereunder. He manages the Company’s Information Security Team, which comprises cybersecurity professionals responsible for the day-to-day operation of the Company’s cybersecurity program and managing the Company’s threat intelligence, vulnerability management, forensics, and security architecture systems. APA’s Executive Vice President, Administration, has 36 years of experience managing data and technology in the energy industry, including serving as the Company’s CIO from 2015-2020. He receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The Executive Vice President, Administration, reports directly to APA’s Chief Executive Officer and presents all relevant information to the Cybersecurity Committee.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	The Cybersecurity Committee reports regularly to the full Board of Directors, with respect to such matters as are relevant to the committee’s discharge of its responsibilities and with respect to such recommendations as the committee deems appropriate for consideration by the Board of Directors. The Cybersecurity Committee also refers to the Audit Committee any matters that come to the attention of the Cybersecurity Committee that fall within the purview of the Audit Committee, including any matters related to the Company’s internal control over financial reporting.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	APA’s Executive Vice President, Administration, has 36 years of experience managing data and technology in the energy industry, including serving as the Company’s CIO from 2015-2020. He receives regular updates from external cybersecurity specialists on emerging trends, threats, and technologies in the cybersecurity industry. The Executive Vice President, Administration, reports directly to APA’s Chief Executive Officer and presents all relevant information to the Cybersecurity Committee.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	The Cybersecurity Committee receives regular reports from Company management regarding the Company’s cybersecurity systems and programs, and the committee from time to time also receives updates from external cybersecurity specialists on cybersecurity trends and incidents, including those that may be particularly relevant to the Company’s industry or operations. In addition, in exercising its oversight responsibilities, the Cybersecurity Committee has full access to Company management and may inquire into any matter that it considers to be of material concern to the committee or the full Board of Directors.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

NATURE OF OPERATIONS	12 Months Ended
NATURE OF OPERATIONS	Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Nature of Operations APA Corporation (APA or the Company) is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids. The Company’s business has oil and gas operations in three geographic areas: the United States (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.

DEBT AND FINANCING COSTS - Commercial Paper Program (Details) - Commercial paper - USD ($)	1 Months Ended
	Dec. 31, 2023	Dec. 31, 2025	Jun. 20, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Debt instrument, face amount		$ 2,000,000,000.0	$ 1,800,000,000
Debt instrument, term	397 days
Debt instrument guarantee terms, benchmark amount (less than)	$ 1,000,000,000.0
Short-term debt		0		$ 323,000,000
The CP Notes
Debt Instrument [Line Items]
Short-term debt		$ 0		$ 323,000,000

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

RETIREMENT AND DEFERRED COMPENSATION PLANS - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Salary increases	4.70%	4.60%	4.70%
Expected return on assets	5.70%	4.80%	4.70%
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 1
Interest cost	6	6	5
Expected return on assets	(8)	(7)	(7)
Amortization of actuarial gain	0	0	0
Curtailment gain	0	0	0
Net periodic benefit cost	$ (1)	$ 0	$ (1)
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.60%	4.80%	5.00%
Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 1	$ 1	$ 1
Interest cost	1	1	1
Expected return on assets	0	0	0
Amortization of actuarial gain	(2)	(2)	(2)
Curtailment gain	0	(1)	0
Net periodic benefit cost	$ 0	$ (1)	$ 0
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.49%	5.00%	5.29%
Healthcare cost trend
Initial	6.50%	6.25%	6.50%
Ultimate in 2032	5.25%	5.25%	5.25%

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Extractive Industries [Abstract]
Sales, net of production costs	$ (5,073)	$ (5,806)	$ (5,408)
Net change in prices and production costs	(2,859)	269	(7,089)
Discoveries and improved recovery, net of related costs	762	3,557	1,869
Change in future development costs	(993)	(695)	(413)
Previously estimated development costs incurred during the period	1,592	793	825
Revision of quantities	3,718	(428)	(262)
Purchases of minerals in-place	0	4,166	1
Accretion of discount	1,438	1,357	2,260
Change in income taxes	999	737	1,467
Sales of minerals in-place	(312)	(1,865)	(18)
Change in production rates and other	(13)	(547)	(793)
Change in the discounted future net cash flows, Total	$ (741)	$ 1,538	$ (7,561)

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

Legal Matters

The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls, which also may include controls related to the potential impacts of climate change. As of December 31, 2025, the Company has an accrued liability of approximately $23 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. With respect to material matters for which the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

Australian Operations Divestiture Dispute

Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. In 2018, Quadrant was acquired by Australian oil and gas company Santos, Ltd., who assumed Quadrant’s place in the ongoing litigation. In early 2025, Santos amended the pending counterclaims to abandon a number of claims that had been asserted against the Company but maintaining counterclaims for approximately AUD $57 million. Santos then filed a new lawsuit in the Supreme Court of Western Australia contending that it may be liable to the Australian Taxation Office for assessments, penalties, and interest related to the 2014 and 2015 tax years of approximately AUD $133 million and asserting that, if such amounts must be paid, the Company is liable to Santos for those amounts under the Quadrant SPA. All lawsuits related to the Quadrant SPA have now been consolidated into the same proceeding. The Company will vigorously prosecute its claim while vigorously defending against any counterclaims.

Delaware Litigation

On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. The Company is vigorously defending the suit.

Kulp Minerals Lawsuit

On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case was not certified and sought to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. On December 5, 2025, the plaintiff voluntarily dismissed the case with prejudice.

Environmental Matters

As of December 31, 2025, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.

The Company is not aware of any environmental claims existing as of December 31, 2025, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of America (GOA) Shelf operations and properties and its GOA operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOA Assets). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, the Legacy GOA Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOA Assets are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOA Assets. The decommissioning obligations for the Legacy GOA Assets are partially secured by a trust account of which Apache is a beneficiary and which is funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf’s second bankruptcy to loan GOM Shelf up to $400 million to perform decommissioning, with such loans and related obligations secured by first and prior liens on the Legacy GOA Assets.

By letter dated April 5, 2022 (replacing two earlier letters) and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it was obligated to perform on certain of the Legacy GOA Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE and demands from third parties to decommission certain of the Legacy GOA Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders and demands on the other Legacy GOA Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOA Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOA Assets.

As of December 31, 2025, the Company recorded an asset of $40 million representing the remaining amount the Company expects to be reimbursed from remaining security related to these decommissioning costs. Of the total asset recorded as of December 31, 2025, $21 million is reflected under the caption “Decommissioning security for sold Gulf of America properties,” and $19 million is reflected under “Other current assets” in the Company’s consolidated balance sheet.

As of December 31, 2025, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOA Assets and assets previously sold to other operators ranges from $0.9 billion to $1.2 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company recorded contingent liabilities in the amounts of $881 million and $1.0 billion as of December 31, 2025, and December 31, 2024, respectively. Of the total liability recorded as of December 31, 2025, $782 million is reflected under the caption “Decommissioning contingency for sold Gulf of America properties” and $99 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected well decommissioning spread rates, derrick barge rates, planned abandonment logistics, and future cash flows of GOM Shelf, could result in a liability in excess of the amount accrued.

The Company recognized $60 million of gains on previously sold Gulf of America properties during 2025 to reflect the net impact of decreased estimated decommissioning costs of Legacy GOA Assets which BSSE may order the Company to decommission. The Company recognized losses on previously sold Gulf of America properties of $273 million and 212 million during 2024 and 2023, respectively, in the Company’s statement of consolidated operations.

Leases and Contractual Obligations

The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, the Company records a Right-of-Use (ROU) asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable.

Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $148 million, $170 million, and $168 million for the years ended 2025, 2024, and 2023, respectively. As allowed under the standard, the Company accounts for non-lease and lease components as a single lease component for all asset classes and has elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases were $69 million, $85 million, and $71 million in 2025, 2024, and 2023, respectively. In 2025 and 2024, these costs primarily related to short term drilling rigs in the U.S. and decommissioning work in the Gulf of America. In 2023 these costs primarily related to decommissioning work in the Gulf of America.

Finance lease assets are included in “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million in each of the years 2025, 2024, and 2023. Interest on the Company’s finance lease liability was $1 million in each of the years 2025, 2024, and 2023.

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2025:


	Operating Leases		Finance Lease
Weighted average remaining lease term	6.8 years		7.7 years
Weighted average discount rate	5.9	%	4.4	%

At December 31, 2025, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:


Net Minimum Commitments(1)	Operating Leases(2)		Finance Lease(3)		Purchase Obligations(4)

	(In millions)
2026	$	103	$	4	$	243
2027	70		4		214
2028	53		4		182
2029	41		4		156
2030	25		4		119
Thereafter	136		14		57
Total future minimum payments	428		34		$	971
Less: imputed interest	(111)		(6)		N/A
Total lease liabilities	317		28		N/A
Current portion	97		3		N/A
Non-current portion	$	220	$	25	N/A

(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.

(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.

The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $52 million, $48 million, and $74 million in 2025, 2024, and 2023, respectively.

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Acquisitions	$ 33	$ 4,564	$ 25
Exploration	352	439	432
Development	2,472	2,859	2,262
Costs incurred	2,857	7,862	2,719
Capitalized interest	45	29	24
Asset retirement costs	135	316	371
United States
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Acquisitions	23	4,561	21
Exploration	76	150	31
Development	1,558	2,067	1,148
Costs incurred	1,657	6,778	1,200
Capitalized interest	6	3	0
Asset retirement costs	51	171	(4)
Unproved		955
Egypt
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Acquisitions	10	3	4
Exploration	244	227	226
Development	530	559	646
Costs incurred	784	789	876
Capitalized interest	0	0	0
Asset retirement costs	0	0	0
North Sea
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Acquisitions	0	0	0
Exploration	1	1	44
Development	96	186	468
Costs incurred	97	187	512
Capitalized interest	0	0	0
Asset retirement costs	84	145	375
Other International
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Acquisitions	0	0	0
Exploration	31	61	131
Development	288	47	0
Costs incurred	319	108	131
Capitalized interest	39	26	24
Asset retirement costs	$ 0	$ 0	$ 0

CAPITAL STOCK - Schedule of Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Movement In Common Stock Outstanding [Roll Forward]
Balance, beginning of year (in shares)	365,397,149	303,575,901	311,559,149
Shares issued for stock-based compensation plans:
Treasury shares issued (in shares)	0	0	2,016
Common shares issued (in shares)	458,481	70,983,745	725,914
Treasury shares acquired (in shares)	(12,890,984)	(9,162,497)	(8,711,178)
Balance, end of year (in shares)	352,964,646	365,397,149	303,575,901

CAPITAL STOCK - Schedule of Stock-settled and Cash-settled Compensation Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 107	$ 49	$ 84
Stock-settled and cash-settled compensation capitalized	15	9	13
Total stock-settled and cash-settled compensation costs	122	58	97
Lease operating expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	26	16	27
Exploration
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	7	4	7
General and administrative
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-settled and cash-settled compensation expensed	$ 74	$ 29	$ 50

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

DEBT AND FINANCING COSTS (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Debt

The following table presents the carrying value of the Company’s debt as of December 31, 2025 and 2024:


	December 31,
	2025		2024

	(In millions)

4.625% notes due 2025	$	—	$	51
7.70% notes due 2026(1)(3)	79		78
7.95% notes due 2026(1)(3)	132		132
4.875% notes due 2027(1)(2)	108		108
4.375% notes due 2028(1)(2)	315		325
7.75% notes due 2029(1)(3)(4)	232		235
4.250% notes due 2030(1)(2)	475		516
6.10% notes due 2035(2)	350		—
6.000% notes due 2037(1)(2)	433		443
5.100% notes due 2040(1)(2)	763		1,333
5.250% notes due 2042(1)(2)	244		399
4.750% notes due 2043(1)(2)	217		428
4.250% notes due 2044(1)(2)	100		211
7.375% debentures due 2047(1)(3)	150		150
5.350% notes due 2049(1)(2)	374		387
6.75% notes due 2055(2)	500		—
7.625% debentures due 2096(1)(3)	39		39
Notes and debentures before unamortized discount and debt issuance costs(5)(6)	4,511		4,835
Commercial paper	—		323
Term loan facility	—		900
Syndicated credit facilities(7)	—		10
Apache finance lease obligations	28		30
Unamortized discount	(23)		(25)
Debt issuance costs	(23)		(29)
Total debt	4,493		6,044
Current maturities	(213)		(53)
Long-term debt	$	4,280	$	5,991

(2)These notes are redeemable, in whole or in part, at the issuer’s option, subject to a make-whole premium.

(4)Outstanding 7.75% notes due 2029 for which Apache is obligated were assumed by Apache in August 2017 as permitted by terms of such notes originally issued by a subsidiary and guaranteed by Apache.

(7)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.

Schedule of Maturities of Long-Term Debt

Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2025 are as follows:


	(In millions)
2026	$	211
2027	108
2028	315
2029	232
2030	475
Thereafter	3,170
Notes and debentures, excluding discounts and debt issuance costs	$	4,511

Schedule of Components of Financing Costs, Net

The following table presents the components of the Company’s financing costs, net:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Interest expense	$	323	$	402	$	351
Amortization of debt issuance costs	7		6		4
Capitalized interest	(45)		(29)		(24)
Gain on extinguishment of debt	(147)		—		(9)
Interest income	(25)		(12)		(10)
Financing costs, net	$	113	$	367	$	312

ACQUISITIONS AND DIVESTITURES - Schedule of Pro Forma Adjustment (Details) - Callon Petroleum Company - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2024
Business Combination [Line Items]
Revenues	$ 10,578	$ 10,300
Net income attributable to common stock	$ 4,021	$ 909
Net income per common share – basic (in USD per share)	$ 10.66	$ 2.45
Net income per common share – diluted (in USD per share)	$ 10.63	$ 2.45

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
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-Publisher FASB
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+ Details

CAPITALIZED EXPLORATORY WELL COSTS (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Schedule of Capitalized Exploratory Well Costs, Roll Forward


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Capitalized well costs at beginning of year	$	237	$	586	$	474
Additions pending determination of proved reserves	234		240		265

Reclassifications to proved properties	(118)		(506)		(135)
Charged to exploration expense	(15)		(83)		(18)
Capitalized well costs at end of year	$	338	$	237	$	586

Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging


	2025		2024		2023

	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	158	$	107	$	156
Exploratory well costs capitalized for a period greater than one year	180		130		430
Capitalized well costs at end of year	$	338	$	237	$	586

Number of projects with exploratory well costs capitalized for a period greater than one year	7		12		33

Schedule of Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year


	Total		2024		2023		2022 and Prior

	(In millions)
Suriname	$	121	$	—	$	60	$	61
United States	48		48		—		—
Egypt	11		7		4		—

	$	180	$	55	$	64	$	61

ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 7,003	$ 6,362	$ 3,691	$ 1,345
Pension and postretirement benefit plan (Note 11)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	10	12	15
Accumulated other comprehensive income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Equity	$ 10	$ 12	$ 15	$ 14

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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+ Details

- Definition

Amount of equity (deficit) attributable to parent and noncontrolling interest. Excludes temporary equity.

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+ Details

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values. The Company elected not to designate any of its derivative contracts as cash flow hedges.

Counterparty Risk

The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2025, the Company had derivative positions with 10 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 2025, the Company had the following open natural gas financial basis swap contracts:

Basis Swap Purchased

Basis Swap Sold

Production Period

Settlement Index

MMBtu
(in 000’s)

Weighted Average Price Differential

MMBtu
(in 000’s)

Weighted Average Price Differential

January—December 2026

NYMEX Henry Hub/IF Waha

89,425

$(1.96)

—

Foreign Currency Derivative Instruments

Subsequent to December 31, 2025, the Company entered into foreign currency costless collar contracts in GBP/USD for £12 million per each calendar month for March through December 2026, with a weighted average floor and ceiling price of $1.32 and $1.40, respectively.

Fair Value Measurements

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)		Carrying Amount

	(In millions)
December 31, 2025



Liabilities:
Commodity derivative instruments	$	—	$	77	$	—	$	77	$	—	$	77



December 31, 2024


Liabilities:

Contingent consideration arrangements	$	—	$	18	$	—	$	18	$	—	$	18

(1) The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

The fair values of the Company’s commodity derivative instruments are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.

Derivative Activity Recorded in the Consolidated Balance Sheet

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	For the Year Ended December 31,
	2025		2024

	(In millions)




Current Liabilities: Other current liabilities	$	77	$	—
Deferred Credits and Other Noncurrent Liabilities: Other	$	—	$	18
Total derivative liabilities	$	77	$	18

Derivative Activity Recorded in the Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Realized:
Commodity derivative instruments	$	31	$	2	$	48
Contingent consideration arrangements	(7)		(4)		—



Realized gains (losses), net	24		(2)		48
Unrealized:
Commodity derivative instruments	(77)		(6)		51
Contingent consideration arrangements	—		(2)		—



Unrealized gains (losses), net	(77)		(8)		51
Derivative instrument gains (losses), net	$	(53)	$	(10)	$	99

Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument (gains) losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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+ Details

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details) MMBTU in Thousands, £ in Millions	12 Months Ended
	Dec. 31, 2025 $ / MMBTU MMBTU counterparty	Feb. 26, 2026 GBP (£) $ / MMBTU
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative counterparties \| counterparty	10
Foreign currency derivative instruments \| Subsequent Event
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, notional amount \| £		£ 12
Average floor price		1.32
Average cap price		1.40
Nymex Henry Hub Waha \| January To December 2026 \| Natural Gas \| Basis Swap Purchased
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	89,425
Weighted average price differential (in USD per MMBtu )	(1.96)
Nymex Henry Hub Waha \| January To December 2026 \| Natural Gas \| Basis Swap Sold
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	0
Weighted average price differential (in USD per MMBtu )	0

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Schedule of Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions, except per boe)
2025
Oil and gas production revenues	$	3,819	$	2,637	$	773	$	—	$	7,229
Operating cost:
Depreciation, depletion, and amortization(2)	1,411		625		239		—		2,275
Asset retirement obligation accretion	41		—		117		—		158
Lease operating expenses	724		447		333		—		1,504
Gathering, processing, and transmission	346		24		54		—		424
Exploration expenses	9		101		1		20		131
Impairments related to oil and gas properties	—		18		—		—		18
Production taxes(3)	227		—		—		—		227
Income tax	234		640		23		—		897
	2,992		1,855		767		20		5,634
Results of operations	$	827	$	782	$	6	$	(20)	$	1,595
2024
Oil and gas production revenues	$	4,315	$	2,933	$	948	$	—	$	8,196
Operating cost:
Depreciation, depletion, and amortization(2)	1,314		621		300		—		2,235
Asset retirement obligation accretion	42		—		106		—		148
Lease operating expenses	820		464		406		—		1,690
Gathering, processing, and transmission	354		25		53		—		432
Exploration expenses	134		112		1		66		313
Impairments related to oil and gas properties	315		—		796		—		1,111
Production taxes(3)	268		—		—		—		268
Income tax	235		770		(536)		—		469
	3,482		1,992		1,126		66		6,666
Results of operations	$	833	$	941	$	(178)	$	(66)	$	1,530
2023
Oil and gas production revenues	$	3,018	$	3,029	$	1,338	$	—	$	7,385
Operating cost:
Depreciation, depletion, and amortization(2)	709		521		270		—		1,500
Asset retirement obligation accretion	40		—		76		—		116
Lease operating expenses	593		474		369		—		1,436
Gathering, processing, and transmission	249		33		52		—		334
Exploration expenses	14		119		19		43		195

Production taxes(3)	204		—		—		—		204
Income tax	254		828		414		—		1,496
	2,063		1,975		1,200		43		5,281
Results of operations	$	955	$	1,054	$	138	$	(43)	$	2,104

(1)Includes a noncontrolling interest in Egypt.

(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 16—Business Segment Information.

(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 16—Business Segment Information.

Schedule of Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities


	United States		Egypt(2)		North Sea		Other International		Total(2)

	(In millions)
2025
Acquisitions	$	23	$	10	$	—	$	—	$	33


Exploration	76		244		1		31		352
Development	1,558		530		96		288		2,472
Costs incurred(1)	$	1,657	$	784	$	97	$	319	$	2,857
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	6	$	—	$	—	$	39	$	45
Asset retirement costs	51		—		84		—		135
2024
Acquisitions(3)	$	4,561	$	3	$	—	$	—	$	4,564


Exploration	150		227		1		61		439
Development	2,067		559		186		47		2,859
Costs incurred(1)	$	6,778	$	789	$	187	$	108	$	7,862
(1) Includes capitalized interest and asset retirement costs:
Capitalized interest	$	3	$	—	$	—	$	26	$	29
Asset retirement costs	171		—		145		—		316

2023
Acquisitions	$	21	$	4	$	—	$	—	$	25


Exploration	31		226		44		131		432
Development	1,148		646		468		—		2,262
Costs incurred(1)	$	1,200	$	876	$	512	$	131	$	2,719
(1) Includes capitalized interest, asset retirement costs, and Egypt modernization impacts as follows:
Capitalized interest	$	—	$	—	$	—	$	24	$	24
Asset retirement costs	(4)		—		375		—		371

(2) Includes a noncontrolling interest in Egypt.
(3) Includes acquisitions of unproved properties of $955 million for the U.S. related to the Callon acquisition.


	United States		Egypt(1)		North Sea		Other International		Total(1)

	(In millions)
2025
Proved properties	$	19,690	$	14,724	$	9,757	$	721	$	44,892
Unproved properties	384		99		—		132		615
	20,074		14,823		9,757		853		45,507
Accumulated DD&A	(11,220)		(12,558)		(9,189)		—		(32,967)
	$	8,854	$	2,265	$	568	$	853	$	12,540

2024
Proved properties	$	19,246	$	14,458	$	9,661	$	434	$	43,799
Unproved properties	711		67		—		121		899
	19,957		14,525		9,661		555		44,698
Accumulated DD&A	(11,053)		(12,299)		(8,952)		—		(32,304)
	$	8,904	$	2,226	$	709	$	555	$	12,394

(1)Includes a noncontrolling interest in Egypt.

Schedule of Proved Reserve Data


	Crude Oil and Condensate
	United States	Egypt(1)	North Sea	Suriname	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2022	177,708	108,050	82,580	—	368,338
December 31, 2023	179,542	102,305	61,076	—	342,923
December 31, 2024	184,744	95,990	30,436	—	311,170
December 31, 2025	182,300	101,750	22,136	—	306,186
Proved undeveloped reserves:
December 31, 2022	22,239	8,557	2,873	—	33,669
December 31, 2023	30,948	5,254	—	—	36,202
December 31, 2024	107,283	7,621	—	73,637	188,541
December 31, 2025	121,079	7,578	—	73,789	202,446

Total proved reserves:
Balance December 31, 2022	199,947	116,607	85,453	—	402,007
Extensions, discoveries and other additions	43,613	12,979	301	—	56,893
Purchases of minerals in-place	20	—	—	—	20
Revisions of previous estimates	(3,520)	10,505	(12,002)	—	(5,017)
Production	(28,795)	(32,532)	(12,676)	—	(74,003)
Sales of minerals in-place	(775)	—	—	—	(775)
Balance December 31, 2023	210,490	107,559	61,076	—	379,125
Extensions, discoveries and other additions	100,778	18,115	—	73,637	192,530
Purchases of minerals in-place	124,112	—	—	—	124,112
Revisions of previous estimates	(9,642)	10,521	(21,000)	—	(20,121)
Production	(47,043)	(32,584)	(9,640)	—	(89,267)
Sales of minerals in-place	(86,668)	—	—	—	(86,668)
Balance December 31, 2024	292,027	103,611	30,436	73,637	499,711
Extensions, discoveries and other additions	39,804	17,646	—	—	57,450

Revisions of previous estimates	24,942	20,088	528	152	45,710
Production	(45,817)	(32,017)	(8,828)	—	(86,662)
Sales of minerals in-place	(7,577)	—	—	—	(7,577)
Balance December 31, 2025	303,379	109,328	22,136	73,789	508,632

(1)Includes proved reserves of 36 MMbbls, 35 MMbbls, 36 MMbbls, and 39 MMbbls as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.


	Natural Gas Liquids
	United States	North Sea	Total(1)

	(Thousands of barrels)
Proved developed reserves:
December 31, 2022	158,745	2,230	160,975
December 31, 2023	153,486	1,460	154,946
December 31, 2024	153,523	744	154,267
December 31, 2025	180,690	899	181,589
Proved undeveloped reserves:
December 31, 2022	19,004	76	19,080
December 31, 2023	18,401	—	18,401
December 31, 2024	54,674	—	54,674
December 31, 2025	58,438	—	58,438

Total proved reserves:
Balance December 31, 2022	177,749	2,306	180,055
Extensions, discoveries and other additions	25,711	371	26,082
Purchases of minerals in-place	21	—	21
Revisions of previous estimates	(8,568)	(764)	(9,332)
Production	(22,993)	(453)	(23,446)
Sales of minerals in-place	(33)	—	(33)
Balance December 31, 2023	171,887	1,460	173,347
Extensions, discoveries and other additions	62,988	—	62,988
Purchases of minerals in-place	51,406	—	51,406
Revisions of previous estimates	(20,167)	(277)	(20,444)
Production	(27,039)	(439)	(27,478)
Sales of minerals in-place	(30,878)	—	(30,878)
Balance December 31, 2024	208,197	744	208,941
Extensions, discoveries and other additions	16,232	—	16,232

Revisions of previous estimates	47,852	614	48,466
Production	(27,836)	(459)	(28,295)
Sales of minerals in-place	(5,317)	—	(5,317)
Balance December 31, 2025	239,128	899	240,027


	Natural Gas
	United States	Egypt(1)	North Sea	Total(1)

	(Millions of cubic feet)
Proved developed reserves:
December 31, 2022	1,166,218	399,502	66,292	1,632,012
December 31, 2023	1,003,956	377,144	46,839	1,427,939
December 31, 2024	866,460	332,905	28,028	1,227,393
December 31, 2025	1,095,395	371,335	12,741	1,479,471
Proved undeveloped reserves:
December 31, 2022	210,862	1,068	2,304	214,234
December 31, 2023	99,495	2,612	—	102,107
December 31, 2024	307,775	27,499	—	335,274
December 31, 2025	338,100	27,780	—	365,880

Total proved reserves:
Balance December 31, 2022	1,377,080	400,570	68,596	1,846,246
Extensions, discoveries and other additions	158,118	14,188	3,335	175,641
Purchases of minerals in-place	136	—	—	136
Revisions of previous estimates	(266,664)	83,907	(6,739)	(189,496)
Production	(165,083)	(118,909)	(18,353)	(302,345)
Sales of minerals in-place	(136)	—	—	(136)
Balance December 31, 2023	1,103,451	379,756	46,839	1,530,046
Extensions, discoveries and other additions	354,267	60,366	—	414,633
Purchases of minerals in-place	279,615	—	—	279,615
Revisions of previous estimates	(224,118)	26,792	(4,176)	(201,502)
Production	(176,941)	(106,510)	(14,635)	(298,086)
Sales of minerals in-place	(162,039)	—	—	(162,039)
Balance December 31, 2024	1,174,235	360,404	28,028	1,562,667
Extensions, discoveries and other additions	95,264	65,514	—	160,778

Revisions of previous estimates	386,166	101,230	(3,856)	483,540
Production	(187,793)	(128,033)	(11,431)	(327,257)
Sales of minerals in-place	(34,377)	—	—	(34,377)
Balance December 31, 2025	1,433,495	399,115	12,741	1,845,351

(1) Includes proved reserves of 133 Bcf, 120 Bcf, 127 Bcf, and 134 Bcf as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.


	Total Equivalent Reserves
	United States	Egypt(1)	North Sea	Suriname	Total(1)

	(Thousands barrels of oil equivalent)
Proved developed reserves:
December 31, 2022	530,823	174,633	95,859	—	801,315
December 31, 2023	500,354	165,162	70,343	—	735,859
December 31, 2024	482,677	151,474	35,852	—	670,003
December 31, 2025	545,555	163,639	25,159	—	734,353
Proved undeveloped reserves:
December 31, 2022	76,386	8,735	3,333	—	88,454
December 31, 2023	65,931	5,690	—	—	71,621
December 31, 2024	213,253	12,204	—	73,637	299,094
December 31, 2025	235,867	12,208	—	73,789	321,864

Total proved reserves:
Balance December 31, 2022	607,209	183,368	99,192	—	889,769
Extensions, discoveries and other additions	95,677	15,344	1,228	—	112,249
Purchases of minerals in-place	64	—	—	—	64
Revisions of previous estimates	(56,532)	24,490	(13,889)	—	(45,931)
Production	(79,302)	(52,350)	(16,188)	—	(147,840)
Sales of minerals in-place	(831)	—	—	—	(831)
Balance December 31, 2023	566,285	170,852	70,343	—	807,480
Extensions, discoveries and other additions	222,811	28,176	—	73,637	324,624
Purchases of minerals in-place	222,121	—	—	—	222,121
Revisions of previous estimates	(67,162)	14,986	(21,973)	—	(74,149)
Production	(103,572)	(50,336)	(12,518)	—	(166,426)
Sales of minerals in-place	(144,553)	—	—	—	(144,553)
Balance December 31, 2024	695,930	163,678	35,852	73,637	969,097
Extensions, discoveries and other additions	71,913	28,565	—	—	100,478

Revisions of previous estimates	137,155	36,960	499	152	174,766
Production	(104,952)	(53,356)	(11,192)	—	(169,500)
Sales of minerals in-place	(18,624)	—	—	—	(18,624)
Balance December 31, 2025	781,422	175,847	25,159	73,789	1,056,217

(1) Includes total proved reserves of 59 MMboe, 55 MMboe, 57 MMboe, and 61 MMboe as of December 31, 2025, 2024, 2023, and 2022, respectively, attributable to a noncontrolling interest in Egypt.

Schedule of Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense


	United States		Egypt(1)		North Sea		Suriname		Total(1)

	(In millions)
2025
Cash inflows	$	25,957	$	9,208	$	1,769	$	5,033	$	41,967
Production costs	(9,192)		(1,978)		(1,077)		(1,294)		(13,541)
Development costs	(3,640)		(1,477)		(2,756)		(1,658)		(9,531)
Income tax expense	(587)		(1,686)		565		(578)		(2,286)
Net cash flows	12,538		4,067		(1,499)		1,503		16,609
10 percent discount rate	(4,563)		(971)		630		(867)		(5,771)
Discounted future net cash flows(2)	$	7,975	$	3,096	$	(869)	$	636	$	10,838
2024
Cash inflows	$	27,534	$	9,342	$	2,828	$	5,881	$	45,585
Production costs	(9,665)		(1,716)		(1,399)		(1,436)		(14,216)
Development costs	(4,124)		(1,517)		(2,538)		(1,096)		(9,275)
Income tax expense	(921)		(1,923)		85		(822)		(3,581)
Net cash flows	12,824		4,186		(1,024)		2,527		18,513
10 percent discount rate	(4,317)		(872)		535		(2,280)		(6,934)
Discounted future net cash flows(2)	$	8,507	$	3,314	$	(489)	$	247	$	11,579
2023
Cash inflows	$	21,417	$	9,921	$	5,761	$	—	$	37,099
Production costs	(8,328)		(1,690)		(2,773)		—		(12,791)
Development costs	(2,238)		(1,235)		(2,461)		—		(5,934)
Income tax expense	(949)		(2,222)		(946)		—		(4,117)
Net cash flows	9,902		4,774		(419)		—		14,257
10 percent discount rate	(3,749)		(943)		476		—		(4,216)
Discounted future net cash flows(2)	$	6,153	$	3,831	$	57	$	—	$	10,041

Schedule of Principal Sources of Change In Discounted Future Net Cash Flows

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Sales, net of production costs	$	(5,073)	$	(5,806)	$	(5,408)
Net change in prices and production costs	(2,859)		269		(7,089)
Discoveries and improved recovery, net of related costs	762		3,557		1,869
Change in future development costs	(993)		(695)		(413)
Previously estimated development costs incurred during the period	1,592		793		825
Revision of quantities	3,718		(428)		(262)
Purchases of minerals in-place	—		4,166		1
Accretion of discount	1,438		1,357		2,260
Change in income taxes	999		737		1,467
Sales of minerals in-place	(312)		(1,865)		(18)
Change in production rates and other	(13)		(547)		(793)
	$	(741)	$	1,538	$	(7,561)

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

DEBT AND FINANCING COSTS - Indenture Debt Activity (Details) - USD ($)		12 Months Ended
	Aug. 20, 2025	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jan. 10, 2025
Debt Instrument [Line Items]
Gain (loss) on debt extinguishment		$ 147,000,000	$ 0	$ 9,000,000
Senior Notes \| Open Market Repurchase YTD
Debt Instrument [Line Items]
Debt repurchased principle amount		122,000,000		74,000,000
Debt instrument repurchase program		112,000,000		65,000,000
Discount (premium) to par of debt repurchase		13,000,000		10,000,000
Gain (loss) on debt extinguishment		$ 12,000,000		$ 9,000,000
Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount					$ 850,000,000
4.625% notes due 2025 \| Unsecured Debt
Debt Instrument [Line Items]
Debt redemption price, percentage	100.00%
Debt instrument, face amount	$ 51,000,000
Debt interest rate	4.625%	4.625%

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Details) - Oil and Gas, Exploration and Production - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	$ 7,229	$ 8,196	$ 7,385
Depreciation, depletion, and amortization	2,275	2,235	1,500
Asset retirement obligation accretion	158	148	116
Lease operating expenses	1,504	1,690	1,436
Gathering, processing, and transmission	424	432	334
Exploration expenses	131	313	195
Impairments related to oil and gas properties	18	1,111
Production taxes	227	268	204
Income tax	897	469	1,496
Operating costs	5,634	6,666	5,281
Results of operations	1,595	1,530	2,104
United States
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	3,819	4,315	3,018
Depreciation, depletion, and amortization	1,411	1,314	709
Asset retirement obligation accretion	41	42	40
Lease operating expenses	724	820	593
Gathering, processing, and transmission	346	354	249
Exploration expenses	9	134	14
Impairments related to oil and gas properties	0	315
Production taxes	227	268	204
Income tax	234	235	254
Operating costs	2,992	3,482	2,063
Results of operations	827	833	955
Egypt
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	2,637	2,933	3,029
Depreciation, depletion, and amortization	625	621	521
Asset retirement obligation accretion	0	0	0
Lease operating expenses	447	464	474
Gathering, processing, and transmission	24	25	33
Exploration expenses	101	112	119
Impairments related to oil and gas properties	18	0
Production taxes	0	0	0
Income tax	640	770	828
Operating costs	1,855	1,992	1,975
Results of operations	782	941	1,054
North Sea
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	773	948	1,338
Depreciation, depletion, and amortization	239	300	270
Asset retirement obligation accretion	117	106	76
Lease operating expenses	333	406	369
Gathering, processing, and transmission	54	53	52
Exploration expenses	1	1	19
Impairments related to oil and gas properties	0	796
Production taxes	0	0	0
Income tax	23	(536)	414
Operating costs	767	1,126	1,200
Results of operations	6	(178)	138
Other International
Oil and Gas, Result of Operation, Producing Activity [Line Items]
Oil and gas production revenues	0	0	0
Depreciation, depletion, and amortization	0	0	0
Asset retirement obligation accretion	0	0	0
Lease operating expenses	0	0	0
Gathering, processing, and transmission	0	0	0
Exploration expenses	20	66	43
Impairments related to oil and gas properties	0	0
Production taxes	0	0	0
Income tax	0	0	0
Operating costs	20	66	43
Results of operations	$ (20)	$ (66)	$ (43)

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
NET INCOME INCLUDING NONCONTROLLING INTERESTS	$ 1,692	$ 1,118	$ 3,207
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan	(2)	(3)	1
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTERESTS	1,690	1,115	3,208
Comprehensive income attributable to noncontrolling interest	258	314	352
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$ 1,432	$ 801	$ 2,856

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income, attributable to parent entity. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income (loss) and other comprehensive income (loss), attributable to noncontrolling interests. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 20
-SubTopic 10
-Topic 810
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481231/810-10-45-20

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(23))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
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- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

COMMITMENTS AND CONTINGENCIES - Schedule of Future Minimum Lease Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating Leases
2026	$ 103
2027	70
2028	53
2029	41
2030	25
Thereafter	136
Total future minimum payments	428
Less: imputed interest	(111)
Total lease liabilities	317
Current portion	97	$ 118
Non-current portion	$ 220
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities (Note 6)	Other current liabilities (Note 6)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other
Finance Lease
2026	$ 4
2027	4
2028	4
2029	4
2030	4
Thereafter	14
Total future minimum payments	34
Less: imputed interest	(6)
Total lease liabilities	28	$ 30
Current portion	3
Non-current portion	25
Purchase Obligations
2026	243
2027	214
2028	182
2029	156
2030	119
Thereafter	57
Total future minimum payments	971
Total costs under take or pay and throughout obligation	$ 263	$ 245	$ 182

INCOME TAXES - Schedule of Components of Net Deferred Tax (Asset) Liability (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
U.S. and state net operating losses	$ 2,298	$ 2,487
Capital losses	13	14
Foreign net operating losses	76	55
Tax credits and other tax incentives	36	105
Foreign tax credits	1,935	2,204
Accrued expenses and liabilities	96	76
Asset retirement obligation	1,021	952
Property and equipment	16	45
Equity investments	1	1
Net interest expense limitation	130	287
Lease liability	93	114
Decommissioning contingency for sold Gulf of America properties	200	232
Other	51	0
Total deferred tax assets	5,966	6,572
Valuation allowance	(2,401)	(2,623)	$ (2,630)	$ (4,918)
Net deferred tax assets	3,565	3,949
Deferred tax liabilities:
Property and equipment	1,108	1,060
Right-of-use asset	87	111
Decommissioning security for sold Gulf of America properties	9	40
Other	33	49
Total deferred tax liabilities	1,237	1,260
Net deferred income tax asset	$ 2,328	$ 2,689

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Open Natural Gas Financial Basis Swap Contracts (Details) - Nymex Henry Hub Waha - January To December 2026 - Natural Gas MMBTU in Thousands	12 Months Ended
	Dec. 31, 2025 $ / MMBTU MMBTU
Basis Swap Purchased
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	89,425
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	(1.96)
Basis Swap Sold
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount (in MMBtu) \| MMBTU	0
Weighted average price differential (in USD per MMBtu ) \| $ / MMBTU	0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

INCOME TAXES - Schedule of Net Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
U.S.	$ 1,488	$ 705	$ 627
Foreign	1,303	830	2,256
NET INCOME BEFORE INCOME TAXES	$ 2,791	$ 1,535	$ 2,883

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

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+ Details

BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Schedule of Financial Segment Information

Financial information for each segment is presented below:


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2025
Oil revenues	$	3,010	$	2,177	$	622	$	—	$	5,809
Natural gas revenues	193		460		117		—		770
Natural gas liquids revenues	616		—		34		—		650
Oil, natural gas, and natural gas liquids production revenues	3,819		2,637		773		—		7,229
Purchased oil and gas sales	1,691		—		—		—		1,691
Realized gains on commodity derivative instruments	31		—		—		—		31
	5,541		2,637		773		—		8,951
Operating Expenses:
Lease operating expenses(5)	724		447		333		—		1,504
Gathering, processing, and transmission(5)	346		24		54		—		424
Purchased oil and gas costs(5)	1,070		—		—		—		1,070
Taxes other than income(5)	229		—		—		—		229
Exploration(4)	9		101		1		20		131
Depreciation, depletion, and amortization(5)	1,434		630		240		—		2,304
Asset retirement obligation accretion	41		—		117		—		158
Impairments	18		19		7		—		44
	3,871		1,221		752		20		5,864
Operating Income (Loss)	$	1,670	$	1,416	$	21	$	(20)	3,087
Other Income (Expense):
Gain on divestitures, net									301
Gains on previously sold Gulf of America properties									60
Realized losses on contingent consideration arrangements									(7)
Unrealized losses on commodity derivative instruments									(77)
Other									(8)
General and administrative									(350)
Transaction, reorganization, and separation									(102)
Financing costs, net									(113)
Income Before Income Taxes									$	2,791

Total Assets(3)	$	12,568	$	3,055	$	1,216	$	922	$	17,761
Net Property and Equipment	$	9,019	$	2,306	$	570	$	853	$	12,748
Additions to Net Property and Equipment	$	1,614	$	747	$	13	$	299	$	2,673


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2024
Oil revenues	$	3,572	$	2,620	$	774	$	—	$	6,966
Natural gas revenues	126		313		145		—		584
Natural gas liquids revenues	617		—		29		—		646
Oil, natural gas, and natural gas liquids production revenues	4,315		2,933		948		—		8,196
Purchased oil and gas sales	1,541		—		—		—		1,541
Realized gains on commodity derivative instruments	2		—		—		—		2
	5,858		2,933		948		—		9,739
Operating Expenses:
Lease operating expenses(5)	820		464		406		—		1,690
Gathering, processing, and transmission(5)	354		25		53		—		432
Purchased oil and gas costs(5)	1,047		—		—		—		1,047
Taxes other than income(5)	270		—		—		—		270
Exploration(4)	134		112		1		66		313
Depreciation, depletion, and amortization(5)	1,340		625		301		—		2,266
Asset retirement obligation accretion	42		—		106		—		148
Impairments	320		—		809		—		1,129
	4,327		1,226		1,676		66		7,295
Operating Income (Loss)	$	1,531	$	1,707	$	(728)	$	(66)	2,444
Other Income (Expense):
Gain on divestitures, net									289
Losses on previously sold Gulf of America properties									(273)
Realized losses on contingent consideration arrangements									(4)
Unrealized losses on commodity derivative instruments									(8)
Other									(6)
General and administrative									(372)
Transaction, reorganization, and separation									(168)
Financing costs, net									(367)
Income Before Income Taxes									$	1,535

Total Assets(3)	$	13,870	$	3,606	$	1,324	$	590	$	19,390
Net Property and Equipment	$	9,109	$	2,271	$	712	$	554	$	12,646
Additions to Net Property and Equipment	$	6,609	$	765	$	41	$	84	$	7,499


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2023
Oil revenues	$	2,241	$	2,683	$	1,073	$	—	$	5,997
Natural gas revenues	297		346		237		—		880
Natural gas liquids revenues	480		—		28		—		508
Oil, natural gas, and natural gas liquids production revenues	3,018		3,029		1,338		—		7,385
Purchased oil and gas sales	894		—		—		—		894
Realized gains on commodity derivative instruments	48		—		—		—		48
	3,960		3,029		1,338		—		8,327
Operating Expenses:
Lease operating expenses(5)	593		474		369		—		1,436
Gathering, processing, and transmission(5)	249		33		52		—		334
Purchased oil and gas costs(5)	742		—		—		—		742
Taxes other than income(5)	207		—		—		—		207
Exploration(4)	14		119		19		43		195
Depreciation, depletion, and amortization(5)	745		524		271		—		1,540
Asset retirement obligation accretion	40		—		76		—		116
Impairments	11		—		50		—		61
	2,601		1,150		837		43		4,631
Operating Income (Loss)	$	1,359	$	1,879	$	501	$	(43)	3,696
Other Income (Expense):
Gain on divestitures, net									8
Losses on previously sold Gulf of America properties									(212)

Unrealized gains on commodity derivative instruments									51
Other									18
General and administrative									(351)
Transaction, reorganization, and separation									(15)
Financing costs, net									(312)
Income Before Income Taxes									$	2,883

Total Assets(3)	$	9,221	$	3,503	$	1,970	$	550	$	15,244
Net Property and Equipment	$	5,689	$	2,209	$	1,628	$	512	$	10,038
Additions to Net Property and Equipment	$	1,255	$	834	$	131	$	93	$	2,313

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2025, 2024, and 2023 of:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Oil	$	536	$	686	$	729
Natural gas	114		83		95

(2)Includes a noncontrolling interest in Egypt for all periods presented.

(3)Intercompany balances are excluded from total assets.

(4)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities.

(5)Represents significant segment expense categories that align with the segment-level information that is regularly provided to the CODM. The remaining expenses that comprise the Other Income (Loss) amount by segment are deemed to be other segment expense categories necessary to arrive at the segment profit or loss.

(6)Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported.

CAPITAL STOCK - Schedule of Performance Program Activities (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Units
Assumed Awards from Callon acquisition (in shares)	0	1,498	0
Employee-related liabilities, current	$ 265	$ 223
Performance Program \| Cash-settled conditional restricted stock unit
Units
Non-vested, beginning balance (in shares)	3,972	4,629	4,835
Granted (in shares)	1,605	834	1,536
Assumed Awards from Callon acquisition (in shares)	0	2,934	0
Vested (in shares)	(2,066)	(4,222)	(1,593)
Forfeited (in shares)	(353)	(203)	(99)
Expired, Shares (in shares)	(242)	0	(50)
Non-vested, ending balance (in shares)	2,916	3,972	4,629
Employee-related liabilities, current	$ 14

RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Schedule of Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans


	2025						2024						2023
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year	$	107		$	15		$	118		$	15		$	108		$	15
Service cost	1			1			1			1			1			1
Interest cost	6			1			6			1			5			1
Foreign currency exchange rates	8			—			(2)			—			6			—
Actuarial losses (gains)	(1)			(1)			(11)			—			3			—
Plan curtailments	—			—			—			(1)			—			—
Benefits paid	(6)			(2)			(5)			(2)			(5)			(3)
Retiree contributions	—			1			—			1			—			1
Projected benefit obligation at end of year	115			15			107			15			118			15
Change in Plan Assets
Fair value of plan assets at beginning of year	136			—			150			—			137			—
Actual return (loss) on plan assets	5			—			(8)			—			8			—
Foreign currency exchange rates	10			—			(3)			—			8			—
Employer contributions	2			1			2			1			2			1

Benefits paid	(6)			(2)			(5)			(2)			(5)			(3)
Retiree contributions	—			1			—			1			—			2
Fair value of plan assets at end of year	147			—			136			—			150			—
Funded status at end of year	$	32		$	(15)		$	29		$	(15)		$	32		$	(15)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(1)		$	—		$	(2)		$	—		$	(2)
Non-current asset (liability)	32			(14)			29			(13)			32			(13)
	$	32		$	(15)		$	29		$	(15)		$	32		$	(15)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(18)		$	14		$	(16)		$	14		$	(12)		$	16

Weighted Average Assumptions used as of December 31
Discount rate	5.60		%	5.18		%	5.60		%	5.49		%	4.80		%	5.00		%
Salary increases	4.50		%	N/A			4.70		%	N/A			4.60		%	N/A
Expected return on assets	5.60		%	N/A			5.70		%	N/A			4.80		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			6.50		%	N/A			6.25		%
Ultimate in 2035	N/A			5.25		%	N/A			5.25		%	N/A			5.25		%

Schedule of Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset

A breakout of allocations for the Company's plan asset holdings are summarized below:


	Percentage of Plan Assets at Year-End
	2025		2024
Asset Category

Multi-asset credit	61	%	62	%
Nominal bonds	3	%	4	%
Inflation-linked bonds	36	%	33	%
Cash	—	%	1	%
Total	100	%	100	%

Schedule of Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets

The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets as follows:


	December 31,
	2025		2024

	(In millions)
Asset Category

Multi-asset credit	90		84
Nominal bonds	3		6
Inflation-linked bonds	53		45
Cash	1		1
Total	$	147	$	136

Schedule of Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans


	2025						2024						2023
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits

	(In millions)
Components of Net Periodic Benefit Cost
Service cost	$	1		$	1		$	1		$	1		$	1		$	1
Interest cost	6			1			6			1			5			1
Expected return on assets	(8)			—			(7)			—			(7)			—
Amortization of actuarial gain	—			(2)			—			(2)			—			(2)
Curtailment gain	—			—			—			(1)			—			—

Net periodic benefit cost	$	(1)		$	—		$	—		$	(1)		$	(1)		$	—
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate	5.60		%	5.49		%	4.80		%	5.00		%	5.00		%	5.29		%
Salary increases	4.70		%	N/A			4.60		%	N/A			4.70		%	N/A
Expected return on assets	5.70		%	N/A			4.80		%	N/A			4.70		%	N/A
Healthcare cost trend
Initial	N/A			6.50		%	N/A			6.25		%	N/A			6.50		%
Ultimate in 2032	N/A			5.25		%	N/A			5.25		%	N/A			5.25		%

Schedule of Expected Future Benefit Payment

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits

	(In millions)
2026	$	5	$	1
2027	7		1
2028	7		1
2029	7		1
2030	7		1
Years 2031-2035	39		7

ACQUISITIONS AND DIVESTITURES - Schedule of Assets Acquired and Liabilities Assumed (Details) - Callon Petroleum Company $ in Millions	Apr. 01, 2024 USD ($)
Business Combination [Line Items]
Current assets	$ 287
Property and equipment	4,502
Deferred tax asset	565
Other assets	12
Total assets acquired	5,366
Current liabilities	632
Long-term debt	2,113
Asset retirement obligation	136
Other long-term obligations	48
Total liabilities assumed	2,929
Net assets acquired	$ 2,437

ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes to Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2025 and 2024:


	For the Year Ended December 31,
	2025		2024

	(In millions)
Asset retirement obligation at beginning of the year	$	2,694	$	2,438
Liabilities incurred	23		15
Liabilities acquired	—		136
Liabilities divested	(8)		(272)
Liabilities settled	(100)		(70)
Accretion expense	158		148
Revisions in estimated liabilities	113		299

Asset retirement obligation at end of the year	2,880		2,694
Less current portion	(181)		(103)
Asset retirement obligation, long-term	$	2,699	$	2,591

INCOME TAXES - Schedule of Foreign Tax Credit Carryforward (Details) $ in Millions	Dec. 31, 2025 USD ($)
Foreign
Tax Credit Carryforward [Line Items]
Tax credit carryforward, amount	$ 1,935

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

DEBT AND FINANCING COSTS - Uncommitted Lines of Credit (Details) - Apache credit facility £ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2025 GBP (£)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 GBP (£)
Debt Instrument [Line Items]
Letters of credit outstanding, amount	$ 10,000,000	£ 901	$ 11,000,000	£ 640
Line of Credit
Debt Instrument [Line Items]
Line of credit outstanding	$ 0		$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

- Definition

+ References + Details

INCOME TAXES - Schedule of Total Provision for Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current income taxes:
Federal		$ (104)	$ 76	$ 2
State		(1)	2	6
Foreign		844	1,075	1,330
Total current income taxes		739	1,153	1,338
Deferred income taxes:
Federal	$ (1,700)	384	(96)	(1,708)
State		41	3	(32)
Foreign		(65)	(643)	78
Total deferred income taxes		360	(736)	(1,662)
Total		$ 1,099	$ 417	$ (324)

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Schedule of Derivative Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative [Line Items]
Total derivative liabilities	$ 77	$ 18
Commodity derivative instruments
Derivative [Line Items]
Derivative liability, fair value	77
Derivative liability, netting	0
Total derivative liabilities	77
Commodity derivative instruments \| Fair Value, Inputs, Level 1
Derivative [Line Items]
Derivative liability, fair value	0
Commodity derivative instruments \| Fair Value, Inputs, Level 2
Derivative [Line Items]
Derivative liability, fair value	77
Commodity derivative instruments \| Fair Value, Inputs, Level 3
Derivative [Line Items]
Derivative liability, fair value	$ 0
Contingent consideration arrangements
Derivative [Line Items]
Derivative liability, fair value		18
Derivative liability, netting		0
Total derivative liabilities		18
Contingent consideration arrangements \| Fair Value, Inputs, Level 1
Derivative [Line Items]
Derivative liability, fair value		0
Contingent consideration arrangements \| Fair Value, Inputs, Level 2
Derivative [Line Items]
Derivative liability, fair value		18
Contingent consideration arrangements \| Fair Value, Inputs, Level 3
Derivative [Line Items]
Derivative liability, fair value		$ 0

- Definition

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References + Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

- Definition

+ References

+ Details

BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

BUSINESS SEGMENT INFORMATION

As of December 31, 2025, the Company’s consolidated subsidiaries are engaged in exploration, development and/or production activities across four operating segments: Egypt, North Sea, Suriname, and the U.S. The Company’s business explores for, develops, and produces crude oil, natural gas, and natural gas liquids. The Company also has exploration interests in Uruguay, Alaska, and other international locations that may, over time, result in reportable discoveries and development opportunities.

The Chief Operating Decision Maker (CODM) is a function (not necessarily an individual) that allocates the resources of the reporting entity and assesses the performance of its segments. Decisions to assess performance and allocate resources are made by the Company’s Chief Executive Officer (CEO), Mr. John J. Christmann, IV. Therefore, management has concluded that the CEO of the Company is the CODM. The information regularly reviewed by the CODM to assess performance and allocate resources is primarily associated with operating income from each segment and the resulting free cash flow, amongst other metrics. The Company concluded that the most comparable measure under U.S. GAAP is operating income.

Financial information for each segment is presented below:


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2025
Oil revenues	$	3,010	$	2,177	$	622	$	—	$	5,809
Natural gas revenues	193		460		117		—		770
Natural gas liquids revenues	616		—		34		—		650
Oil, natural gas, and natural gas liquids production revenues	3,819		2,637		773		—		7,229
Purchased oil and gas sales	1,691		—		—		—		1,691
Realized gains on commodity derivative instruments	31		—		—		—		31
	5,541		2,637		773		—		8,951
Operating Expenses:
Lease operating expenses(5)	724		447		333		—		1,504
Gathering, processing, and transmission(5)	346		24		54		—		424
Purchased oil and gas costs(5)	1,070		—		—		—		1,070
Taxes other than income(5)	229		—		—		—		229
Exploration(4)	9		101		1		20		131
Depreciation, depletion, and amortization(5)	1,434		630		240		—		2,304
Asset retirement obligation accretion	41		—		117		—		158
Impairments	18		19		7		—		44
	3,871		1,221		752		20		5,864
Operating Income (Loss)	$	1,670	$	1,416	$	21	$	(20)	3,087
Other Income (Expense):
Gain on divestitures, net									301
Gains on previously sold Gulf of America properties									60
Realized losses on contingent consideration arrangements									(7)
Unrealized losses on commodity derivative instruments									(77)
Other									(8)
General and administrative									(350)
Transaction, reorganization, and separation									(102)
Financing costs, net									(113)
Income Before Income Taxes									$	2,791

Total Assets(3)	$	12,568	$	3,055	$	1,216	$	922	$	17,761
Net Property and Equipment	$	9,019	$	2,306	$	570	$	853	$	12,748
Additions to Net Property and Equipment	$	1,614	$	747	$	13	$	299	$	2,673


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2024
Oil revenues	$	3,572	$	2,620	$	774	$	—	$	6,966
Natural gas revenues	126		313		145		—		584
Natural gas liquids revenues	617		—		29		—		646
Oil, natural gas, and natural gas liquids production revenues	4,315		2,933		948		—		8,196
Purchased oil and gas sales	1,541		—		—		—		1,541
Realized gains on commodity derivative instruments	2		—		—		—		2
	5,858		2,933		948		—		9,739
Operating Expenses:
Lease operating expenses(5)	820		464		406		—		1,690
Gathering, processing, and transmission(5)	354		25		53		—		432
Purchased oil and gas costs(5)	1,047		—		—		—		1,047
Taxes other than income(5)	270		—		—		—		270
Exploration(4)	134		112		1		66		313
Depreciation, depletion, and amortization(5)	1,340		625		301		—		2,266
Asset retirement obligation accretion	42		—		106		—		148
Impairments	320		—		809		—		1,129
	4,327		1,226		1,676		66		7,295
Operating Income (Loss)	$	1,531	$	1,707	$	(728)	$	(66)	2,444
Other Income (Expense):
Gain on divestitures, net									289
Losses on previously sold Gulf of America properties									(273)
Realized losses on contingent consideration arrangements									(4)
Unrealized losses on commodity derivative instruments									(8)
Other									(6)
General and administrative									(372)
Transaction, reorganization, and separation									(168)
Financing costs, net									(367)
Income Before Income Taxes									$	1,535

Total Assets(3)	$	13,870	$	3,606	$	1,324	$	590	$	19,390
Net Property and Equipment	$	9,109	$	2,271	$	712	$	554	$	12,646
Additions to Net Property and Equipment	$	6,609	$	765	$	41	$	84	$	7,499


	U.S.		Egypt(1)		North Sea		Intersegment Eliminations & Other(6)		Total(2)


	(In millions)
2023
Oil revenues	$	2,241	$	2,683	$	1,073	$	—	$	5,997
Natural gas revenues	297		346		237		—		880
Natural gas liquids revenues	480		—		28		—		508
Oil, natural gas, and natural gas liquids production revenues	3,018		3,029		1,338		—		7,385
Purchased oil and gas sales	894		—		—		—		894
Realized gains on commodity derivative instruments	48		—		—		—		48
	3,960		3,029		1,338		—		8,327
Operating Expenses:
Lease operating expenses(5)	593		474		369		—		1,436
Gathering, processing, and transmission(5)	249		33		52		—		334
Purchased oil and gas costs(5)	742		—		—		—		742
Taxes other than income(5)	207		—		—		—		207
Exploration(4)	14		119		19		43		195
Depreciation, depletion, and amortization(5)	745		524		271		—		1,540
Asset retirement obligation accretion	40		—		76		—		116
Impairments	11		—		50		—		61
	2,601		1,150		837		43		4,631
Operating Income (Loss)	$	1,359	$	1,879	$	501	$	(43)	3,696
Other Income (Expense):
Gain on divestitures, net									8
Losses on previously sold Gulf of America properties									(212)

Unrealized gains on commodity derivative instruments									51
Other									18
General and administrative									(351)
Transaction, reorganization, and separation									(15)
Financing costs, net									(312)
Income Before Income Taxes									$	2,883

Total Assets(3)	$	9,221	$	3,503	$	1,970	$	550	$	15,244
Net Property and Equipment	$	5,689	$	2,209	$	1,628	$	512	$	10,038
Additions to Net Property and Equipment	$	1,255	$	834	$	131	$	93	$	2,313

(1)Includes oil and gas production revenue that will be paid as taxes by EGPC on behalf of the Company for the years ended December 31, 2025, 2024, and 2023 of:


	For the Year Ended December 31,
	2025		2024		2023

	(In millions)
Oil	$	536	$	686	$	729
Natural gas	114		83		95

(2)Includes a noncontrolling interest in Egypt for all periods presented.

(3)Intercompany balances are excluded from total assets.

(4)Exploration expense under Intersegment Eliminations & Other primarily reflects the Company’s Suriname exploration activities.

(6)Includes Suriname operating expenses as the operating segment has not met the quantitative thresholds to be separately reported.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://fasb.org/us-gaap/role/ref/otherTransitionRef
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Reference 12: http://www.xbrl.org/2003/role/exampleRef
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Reference 13: http://www.xbrl.org/2003/role/exampleRef
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Reference 14: http://www.xbrl.org/2003/role/exampleRef
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Reference 15: http://www.xbrl.org/2003/role/exampleRef
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+ Details

CONSOLIDATED BALANCE SHEET - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
CURRENT ASSETS:
Cash and cash equivalents	$ 516	$ 625
Receivables, net of allowance of $140 and $123	1,062	1,959
Other current assets (Note 5)	543	820
Total current assets	2,121	3,404
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of successful efforts accounting:	45,507	44,698
Gathering, processing, and transmission facilities	445	433
Other	536	562
Less: Accumulated depreciation, depletion, and amortization	(33,740)	(33,047)
Property and equipment, net	12,748	12,646
OTHER ASSETS:
Decommissioning security for sold Gulf of America properties (Note 10)	21	21
Deferred tax asset (Note 9)	2,328	2,703
Deferred charges and other	543	616
ASSETS	17,761	19,390
CURRENT LIABILITIES:
Accounts payable	871	1,224
Current debt	213	53
Other current liabilities (Note 6)	1,487	1,678
Total current liabilities	2,571	2,955
LONG-TERM DEBT (Note 8)	4,280	5,991
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Deferred tax liability (Note 9)	0	14
Asset retirement obligation (Note 7)	2,699	2,591
Decommissioning contingency for sold Gulf of America properties (Note 10)	782	929
Other	426	548
Total deferred credits and other noncurrent liabilities	3,907	4,082
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 492,038,127 and 491,579,646 shares issued, respectively	308	307
Paid-in capital	12,816	13,153
Accumulated deficit	(721)	(2,155)
Treasury stock, at cost, 139,073,481 and 126,182,497 shares, respectively	(6,320)	(6,037)
Accumulated other comprehensive income	10	12
APA SHAREHOLDERS’ EQUITY	6,093	5,280
TOTAL EQUITY	7,003	6,362
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY	17,761	19,390
Noncontrolling interest
EQUITY:
Noncontrolling interest	$ 910	$ 1,082

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) $ in Millions, $ in Millions		12 Months Ended
	Sep. 10, 2020 defendant	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2025 AUD ($)	Apr. 05, 2022 letter	Dec. 31, 2017 AUD ($)	Apr. 30, 2017 AUD ($)
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies		$ 23
Undiscounted reserve for environmental remediation		2
Standby loan agreed to provide related to ARO		400
Number of prior letters notifying unable to fund decommissioning obligations \| letter						2
Decommissioning security for sold properties		40
Decommissioning security for sold Gulf of America properties (Note 10)		21	$ 21
Current decommissioning security for sold Gulf of America assets		19	157
Decommissioning contingency for sold Gulf of America properties (Note 10)		782	929
Current decommissioning contingency for sold Gulf of America properties		99	88
(Gains) losses on previously sold Gulf of America properties		(60)	273	$ 212
Fixed operating lease expenses		148	170	168
Short-term lease expense		69	85	71
Depreciation on finance lease asset		2	2	2
Interest on finance lease asset		1	1	1
Variable lease payment		52	48	$ 74
Minimum
Commitment And Contingencies [Line Items]
AROs, estimated liability		900
Decommissioning contingency for sold		881	$ 1,000
Maximum
Commitment And Contingencies [Line Items]
AROs, estimated liability		$ 1,200
Australian Operations Divestiture Dispute \| Apache Australia Operation
Commitment And Contingencies [Line Items]
Gain contingency, unrecorded amount					$ 57			$ 80
Loss contingency, estimated of possible loss amount					$ 133		$ 200
Delaware Litigation
Commitment And Contingencies [Line Items]
Number of defendants \| defendant	25

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) - Additional Information (Details) - MBoe MBoe in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	100	325	112
Revision of previous estimate	175		46
Percentage of estimated proved developed reserves classified as proved not producing	8.00%
Changes in Product Prices
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate			83
Changes in Engineering and Performance
Oil and Gas, Proved Reserve, Quantity [Line Items]
Revision of previous estimate	138		37
United States
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	72	223
United States \| Changes in Engineering and Performance
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		100
International Regions
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		102	16
Egypt
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions	28	28	15
Egypt \| Changes in Engineering and Performance
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		38
Permian Basin
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions			67
Revision of previous estimate	37
Suriname
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions		74
North America
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions			96
Texas Gulf Coast
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions			27
Delaware Basin
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions			2
North Sea
Oil and Gas, Proved Reserve, Quantity [Line Items]
Addition from extensions, discoveries, and other additions			1

ACQUISITIONS AND DIVESTITURES - 2023 Activity (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Business Combination [Line Items]
Proceeds from asset divestitures			$ 611	$ 1,609	$ 29
Kinetik
Business Combination [Line Items]
Shares sold (in shares)	7.5
Aggregate issue price of Preferred Units	$ 228
Disposed of by Sale \| Non-Core Assets And Leasehold
Business Combination [Line Items]
Proceeds from asset divestitures				91	29
Gain (loss) on sale of oil and gas properties				$ 22	8
Permian Region
Business Combination [Line Items]
Payments to acquire oil and gas property					$ 20
Permian Region \| Disposed of by Sale
Business Combination [Line Items]
Gain (loss) on sale of oil and gas properties		$ (5)

ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2025

Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]

Schedule of Business Combination, Pro Forma Information


	For the Year Ended December 31,
	2024		2023

	(In millions)
Revenues	$	10,300	$	10,578
Net income attributable to common stock	909		4,021
Net income per common share – basic	2.45		10.66
Net income per common share – diluted	2.45		10.63

Schedule of Equity Method Investment Information


	For the Year Ended December 31,
	2024		2023

	(In millions)
Natural gas and NGLs sales	$	13	$	92
Purchased oil and gas sales	22		29
	$	35	$	121

Gathering, processing, and transmission costs	$	23	$	108
Purchased oil and gas costs	23		80
Lease operating expenses	2		7
	$	48	$	195

CAPITALIZED EXPLORATORY WELL COSTS - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 180	$ 130	$ 430
Suriname
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 121
Suriname And Egypt
Oil and Gas, Capitalized Exploratory Well Cost, Capitalized for Period Greater than One Year, Aging [Line Items]
Exploratory well costs capitalized for a period greater than one year		$ 8

Cover - USD ($)	12 Months Ended
Cover - USD ($)	Dec. 31, 2025	Jan. 31, 2026	Jun. 30, 2025
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-40144
Entity Registrant Name	APA CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	86-1430562
Entity Address, Address Line One	2000 W. Sam Houston Pkwy. S., Suite 200
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77042-3643
City Area Code	713
Local Phone Number	296-6000
Title of 12(b) Security	Common Stock, $0.625 par value
Trading Symbol	APA
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction	false
Entity Shell Company	false
Entity Public Float			$ 6,561,964,169
Entity Common Stock, Shares Outstanding		353,251,476
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to the registrant’s 2026 annual meeting of stockholders are incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Entity Central Index Key	0001841666

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY AND NONCONTROLLING INTEREST (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share (in USD per share)	$ 1.00	$ 1.00	$ 1.00

ACCUMULATED OTHER COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

Components of accumulated other comprehensive income include the following:


	As of December 31,
	2025		2024		2023

	(In millions)

Pension and postretirement benefit plan (Note 11)	$	10	$	12	$	15
Accumulated other comprehensive income	$	10	$	12	$	15

CAPITAL STOCK - Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Basic:
Income attributable to common stock	$ 1,434	$ 804	$ 2,855
Income attributable to common stock (in shares)	359	353	308
Income attributable to common stock (in USD per share)	$ 3.99	$ 2.28	$ 9.26
Diluted:
Income attributable to common stock		$ 804	$ 2,855
Income attributable to common stock (in shares)	359	353	309
Income attributable to common stock (in USD per share)	$ 3.99	$ 2.27	$ 9.25
Stock compensation awards
Effect of Dilutive Securities:
Stock compensation awards	$ 0	$ 0	$ 0
Stock compensation awards (in shares)	0	0	1
Stock compensation awards (in USD per share)	$ 0	$ (0.01)	$ (0.01)