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Income Taxes - Effective Income Tax Expense (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Effective Income Tax Rate Reconciliation, Amount [Abstract]
U.S. Federal Statutory Tax Rate	$ 479	$ (177)	$ 655
State and Local Income Taxes, Net of Federal Income Tax Effect	42	29	51
Tax credits
Research and development tax credits	(46)	(32)	(10)
Changes in Valuation Allowances	11	9	(28)
Nontaxable or nondeductible items
Merger Related Costs	(21)	33	0
Other	3	1	3
Changes in Unrecognized Tax Benefits	0	0	6
Other adjustments
Return to provision	(35)	0	(16)
Capital loss expirations	30	5	26
Other	0	5	11
Effective Tax Rate	$ 463	$ (127)	$ 698
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal Statutory Tax Rate	21.00%	21.00%	21.00%
State income taxes (net of federal income tax benefit)	1.80%	(3.40%)	1.60%
Tax credits
Research and development tax credits	(2.00%)	3.80%	(0.30%)
Changes in Valuation Allowances	0.50%	(1.10%)	(0.90%)
Nontaxable or nondeductible items
Merger Related Costs	(0.90%)	(3.90%)	0.00%
Other	0.10%	(0.10%)	0.10%
Changes in Unrecognized Tax Benefits	0.00%	0.00%	0.20%
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Percent [Abstract]
Return to provision	(1.50%)	0.00%	(0.50%)
Capital loss expirations	1.30%	(0.60%)	0.80%
Other	0.00%	(0.60%)	0.40%
Effective Tax Rate	20.30%	15.10%	22.40%

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

Earnings Per Share

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Earnings Per Share


3.			Earnings Per Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities utilizing the treasury stock method. Potentially dilutive securities consists of issuable shares related to warrants, unvested restricted stock units (“RSUs”), and unvested performance share units (“PSUs”).

The reconciliations between basic and diluted earnings (loss) per share are as follows:


	Years Ended December 31,
	2025		2024		2023
Numerator
Net income (loss) available to common stockholders, basic and diluted	$	1,819	$	(714)	$	2,419

Denominator (in thousands)
Weighted average common shares outstanding, basic	237,290		156,989		132,840
Effect of potentially dilutive securities
Warrants	2,670		—		9,750
Restricted stock units	372		—		338
Performance share units	38		—		48
Weighted average common shares outstanding, diluted	240,370		156,989		142,976

Earnings per common share:
Basic	$	7.67	$	(4.55)	$	18.21
Diluted	$	7.57	$	(4.55)	$	16.92

During the years ended December 31, 2025, 2024 and 2023, the diluted earnings (loss) per share calculation excludes the effect of 13,391, 308,646 and 777,369 reserved shares of common stock and 25,015, 582,109 and 1,466,502 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases, as all necessary conditions had not been met for such shares to be considered dilutive shares during the years ended December 31, 2025, 2024 and 2023, respectively. Additionally, the diluted loss per share calculation during the year ended December 31, 2024 excludes the antidilutive effect of 9,058,361 Warrants, 315,318 RSUs and 86,421 PSUs.

Leases - Maturity Analysis of Finance and Operating Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
2026	$ 51
2027	34
2028	15
2029	6
2030	0
Thereafter	1
Total lease payments	107
Less imputed interest	(8)
Present value of lease liabilities	99	$ 145
Less current maturities	(51)	(71)
Present value of lease liabilities, less current maturities	$ 48	$ 74

Cover Page - USD ($) $ in Billions	12 Months Ended
Cover Page - USD ($) $ in Billions	Dec. 31, 2025	Feb. 11, 2026	Jun. 30, 2025
Entity Information [Line Items]
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	001-13726
Entity Registrant Name	EXPAND ENERGY CORPORATION
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-1395733
Entity Address, Address Line One	6100 North Western Avenue,
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73118
City Area Code	(405)
Local Phone Number	848-8000
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 Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 19.6
Entity Common Stock, Shares Outstanding		240,398,260
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of the proxy statement for the 2026 Annual Meeting of Stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K.
Amendment Flag	false
Entity Central Index Key	0000895126
Fiscal Year Focus	2025
Fiscal Period Focus	FY
Class A Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class A Warrants to purchase Common Stock
Trading Symbol	EXEEW
Security Exchange Name	NASDAQ
Class B Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class B Warrants to purchase Common Stock
Trading Symbol	EXEEZ
Security Exchange Name	NASDAQ
Class C Warrants to purchase Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Class C Warrants to purchase Common Stock
Trading Symbol	EXEEL
Security Exchange Name	NASDAQ
Common Stock
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value per share
Trading Symbol	EXE
Security Exchange Name	NASDAQ

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Exploration Expense and Cost Incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Acquisition of properties:
Proved properties	$ 5	$ 10,010	$ 10
Unproved properties	409	4,393	52
Exploratory costs	45	17	15
Development costs	2,751	1,420	1,721
Costs incurred	$ 3,210	15,840	$ 1,798
Southwestern
Acquisition of properties:
Proved properties		10,000
Unproved properties		$ 4,300

Derivative and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Estimated Fair Value of Oil, Natural Gas and NGL Derivative Instrument Asset (Liabilities)

The estimated fair values of our natural gas, oil and NGL derivative instrument assets (liabilities) as of December 31, 2025 and 2024 are provided below:


	December 31, 2025			December 31, 2024
	Notional Volume	Fair Value		Notional Volume	Fair Value
Natural gas (Bcf):
Fixed-price swaps	756	$	128	369	$	(28)
Two-way collars	1,143	212		1,098	(27)
Three-way collars	175	32		161	60
Call options (purchased)	—	—		73	1
Call options (sold)	73	(1)		219	(16)
Basis protection swaps	337	(66)		279	(39)
Total natural gas	2,484	305		2,199	(49)
Oil (MMBbls):
Three-way collars	—	$	2	2	$	4
Total oil	—	2		2	4
NGLs (MMBbls):
Fixed-price swaps	—	$	—	7	$	(9)
Total NGL	—	—		7	(9)


Total estimated fair value		$	307		$	(54)

Schedule of Effects of Derivative Instruments in Consolidated Balance Sheets

The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2025 and 2024 on a gross basis and after same-counterparty netting:


	Gross Fair Value(a)		Amounts Netted in the Consolidated Balance Sheets		Net Fair Value Presented in the Consolidated Balance Sheets
As of December 31, 2025
Commodity Contracts:
Short-term derivative asset	$	340	$	(76)	$	264
Long-term derivative asset	66		(19)		47
Short-term derivative liability	(79)		76		(3)
Long-term derivative liability	(20)		19		(1)


Total derivatives	$	307	$	—	$	307

As of December 31, 2024
Commodity Contracts:
Short-term derivative asset	$	191	$	(107)	$	84
Long-term derivative asset	6		(5)		1
Short-term derivative liability	(178)		107		(71)
Long-term derivative liability	(73)		5		(68)


Total derivatives	$	(54)	$	—	$	(54)

___________________________________________

(a)These financial assets (liabilities) are measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below.

Leases - Additional information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Lease cost:
Operating lease cost	$ 91	$ 88	$ 107
Short-term lease cost	45	62	40
Total lease cost	136	150	147
Other information:
Operating cash outflows from operating leases	32	13	10
Investing cash outflows from operating leases	$ 104	$ 137	$ 137
Weighted average remaining lease term - operating leases	2 years 5 months 26 days	3 years 10 days
Weighted average discount rate - operating leases	5.77%	5.99%

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period	$ 531	$ 276
Additions	16	263
Revisions	157	(21)
Settlements and disposals	(10)	(5)
Accretion expense	30	18
Asset retirement obligations, end of period	724	531
Asset retirement obligations	724	531
Less current portion	36	32
Asset retirement obligations, long-term	$ 688	499
Southwestern
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Additions		$ 251

Income Taxes - Deferred Tax Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred tax liabilities:
Property, plant and equipment	$ (2,250)	$ (1,730)
Derivative instruments	(72)	0
Investments	(82)	0
Contracts	(71)	0
Right of use lease asset	(24)	(36)
Other	(5)	(3)
Deferred tax liabilities	(2,504)	(1,769)
Deferred tax assets:
Net operating loss carryforwards	1,613	1,258
Carrying value of debt	1	4
Excess business interest expense carryforward	654	777
Capital loss carryforwards	70	103
Tax credit carryforwards	107	53
Contract liabilities	286	261
Asset retirement obligations	169	123
Future lease payments	25	36
Accrued liabilities	22	39
Derivative instruments	0	13
Other	32	24
Deferred tax assets	2,979	2,691
Valuation allowance	(344)	(343)
Deferred tax assets after valuation allowance	2,635	2,348
Reflected in the accompanying balance sheets as:
Deferred income tax assets	168	589
Other long-term liabilities	(37)	(10)
Net deferred tax asset	$ 131	$ 579

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Schedule of Changes in Unvested Restricted Stock Units

A summary of the changes in unvested RSUs is presented below:


	Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested as of December 31, 2022	957	$	68.91
Granted	440	$	72.25
Vested	(329)	$	61.66
Forfeited	(128)	$	68.42
Unvested as of December 31, 2023	940	$	73.08
Granted (a)	962	$	83.09
Vested (a)	(925)	$	74.18
Forfeited	(20)	$	77.71
Unvested as of December 31, 2024	957	$	81.99
Granted	557	$	103.38
Vested	(520)	$	80.52
Forfeited	(37)	$	98.24
Unvested as of December 31, 2025	957	$	94.61

_________________________________________

(a)During the year ended December 31, 2024, approximately 5.2 million Southwestern RSUs were converted to 478 thousand Company RSUs, of which approximately 384 thousand RSUs were accelerated. We recognized the accelerated share-based compensation expense related to these awards in other operating expense, net on our consolidated statements of operations. Additionally, approximately 105 thousand RSUs were accelerated related to one-time termination benefits for certain employees.

Schedule Valuation Assumptions

The following table presents the assumptions used in the valuation of the PSUs granted during the years ended December 31, 2025, 2024 and 2023.


Assumption - TSR, rTSR	2025 PSU Awards		2024 PSU Awards		2023 PSU Awards
Risk-free interest rate	4.00	%	4.55	%	3.85	%
Volatility	33.40	%	39.36	%	64.4	%

Schedule of the Changes in Unvested Performance Share Units

A summary of the changes in unvested PSUs is presented below:


	Unvested Performance Share Units	Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested as of December 31, 2022	276	$	88.28
Granted	131	$	78.78
Vested	—	$	—
Forfeited	(13)	$	68.77
Unvested as of December 31, 2023	394	$	85.78
Granted	133	$	95.33
Vested	(151)	$	71.29
Forfeited	—	$	—
Unvested as of December 31, 2024	376	$	94.67
Granted	250	$	125.64
Vested	(132)	$	108.56
Forfeited	(30)	$	113.86
Unvested as of December 31, 2025	464	$	106.14

Schedule of Compensation Costs (Credit), Net of Actual Forfeitures

We recognized the following compensation costs, net of actual forfeitures, related to RSUs and PSUs for the periods presented:


	Years Ended December 31,
	2025		2024		2023
General and administrative expenses	$	37	$	33	$	29
Natural gas and oil properties	8		7		6
Production expense	6		4		4
Separation and other termination costs	2		9		—
Marketing expense	3		—		—
Other operating expense, net	4		28		—
Total RSU and PSU compensation	$	60	$	81	$	39
Related income tax benefit	$	13	$	13	$	7

Income Taxes - Federal NOLs and Excess Business Interest (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Income Taxes Summary [Line Items]
Total federal net operating losses	$ 1,613	$ 1,258
Federal
Income Taxes Summary [Line Items]
Indefinitely lived	5,302
Total federal net operating losses	6,765
2031 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	9
2032 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	3
2033 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	2
2034 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	2
2035 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	79
2036 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	642
2037 \| Federal
Income Taxes Summary [Line Items]
Net operating losses, by year of expiration:	$ 726

Contingencies and Commitments

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Contingencies and Commitments


5.			Contingencies and Commitments

Contingencies

Business Operations and Litigation and Regulatory Proceedings

We are involved in, and expect to continue to be involved in, various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We are also party to the consolidated Chapter 11 Cases pending for the Debtors in the Bankruptcy Court.

Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates. While it is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages and are all subject to inherent uncertainties. Therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of our final liabilities being materially different.

The majority of Chesapeake’s pre-petition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court, together with actions seeking to collect pre-petition indebtedness or to exercise control over the property of Chesapeake’s bankruptcy estates. Any allowed claim related to such litigation will be treated in accordance with the Plan. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against Chesapeake’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. Many of these proceedings were in early stages as of the Petition Date, and many of them sought damages and penalties, the amount of which is indeterminate. Any legal proceeding pending against Southwestern and assumed by us in connection with the Southwestern Merger is not subject to discharge or resolution as part of the Chapter 11 Cases.

Environmental Contingencies

The nature of the natural gas and oil business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

Commitments

Gathering, Processing and Transportation Agreements

We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Generally, commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets. See Note 2 for further discussion of commitments recorded on our consolidated balance sheets.

The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:


	December 31, 2025
2026	$	1,428
2027	1,337
2028	1,221
2029	1,019
2030	884
Thereafter	3,683
Total	$	9,572

In addition, we have long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement.

Other Commitments

As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.

In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of natural gas and oil properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title or environmental defects.

While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity.

Share-Based Compensation - Restricted Stock (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Restricted Stock Units (RSUs)
Unvested Restricted Stock Units
Unvested restricted stock, beginning balance (in shares)	957	940	957
Granted (in shares)	557	962	440
Vested (in shares)	(520)	(925)	(329)
Forfeited (in shares)	(37)	(20)	(128)
Unvested restricted stock, ending balance (in shares)	957	957	940
Weighted Average Grant Date Fair Value Per Share
Unvested restricted stock, beginning balance (in usd per share)	$ 81.99	$ 73.08	$ 68.91
Granted (in usd per share)	103.38	83.09	72.25
Vested (in usd per share)	80.52	74.18	61.66
Forfeited (in usd per share)	98.24	77.71	68.42
Unvested restricted stock, ending balance (in usd per share)	$ 94.61	$ 81.99	$ 73.08
Restricted Stock Units (RSUs) \| One-time termination benefits
Weighted Average Grant Date Fair Value Per Share
Number of accelerated vesting units (in shares)		105
Restricted Stock Units (RSUs) \| Southwestern
Unvested Restricted Stock Units
Granted (in shares)		478
Weighted Average Grant Date Fair Value Per Share
Number of accelerated vesting units (in shares)		384
Southwestern Restricted Stock Units (RSUs) \| Southwestern
Unvested Restricted Stock Units
Unvested restricted stock, beginning balance (in shares)	5,200
Unvested restricted stock, ending balance (in shares)		5,200

Revenue

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenue


8.			Revenue

The following tables show revenue disaggregated by operating area and product type, for the periods presented:


	Year Ended December 31, 2025
	Natural Gas		Oil		NGL		Total
Haynesville	$	3,477	$	—	$	—	$	3,477
Northeast Appalachia	2,860		—		—		2,860
Southwest Appalachia	1,096		319		724		2,139
Natural gas, oil and NGL revenue	$	7,433	$	319	$	724	$	8,476

Marketing revenue	$	2,889	$	132	$	142	$	3,163


	Year Ended December 31, 2024
	Natural Gas		Oil		NGL		Total
Haynesville	$	1,205	$	—	$	—	$	1,205
Northeast Appalachia	1,242		—		—		1,242
Southwest Appalachia	239		69		214		522

Natural gas, oil and NGL revenue	$	2,686	$	69	$	214	$	2,969

Marketing revenue	$	1,095	$	116	$	79	$	1,290


	Year Ended December 31, 2023
	Natural Gas		Oil		NGL		Total
Haynesville	$	1,300	$	—	$	—	$	1,300
Northeast Appalachia	1,483		—		—		1,483

Eagle Ford	70		596		98		764

Natural gas, oil and NGL revenue	$	2,853	$	596	$	98	$	3,547

Marketing revenue	$	989	$	1,332	$	179	$	2,500

Major Customers

For the year ended December 31, 2025, we had sales to one purchaser that accounted for 11% of our total revenues (before the effects of hedging). For the year ended December 31, 2024, we had no purchaser that accounted for 10% or greater of our total revenues (before the effects of hedging). For the year ended December 31, 2023, we had sales to two purchasers that accounted for approximately 17% and 10% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the years ended December 31, 2025 or 2023.

Accounts Receivable

Accounts receivable as of December 31, 2025 and 2024 are detailed below:


	December 31, 2025		December 31, 2024
Natural gas, oil and NGL sales	$	1,363	$	1,028
Joint interest	232		191
Other	18		18
Allowance for doubtful accounts	(14)		(11)
Total accounts receivable, net	$	1,599	$	1,226

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Natural Gas and Oil Property Transactions

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Natural Gas and Oil Property Transactions


2.			Natural Gas and Oil Property Transactions

Southwestern Merger

On January 10, 2024, Chesapeake and Southwestern entered into an all-stock agreement and plan of merger (the “Merger Agreement”). Southwestern was an independent energy company engaged in development, exploration and production activities, including related marketing activities, within its operating areas in the Appalachia and Haynesville shale plays. Our Board of Directors and the Board of Directors of Southwestern both approved the Merger Agreement. At separate special meetings each held on June 18, 2024, Chesapeake’s stockholders approved the issuance of Chesapeake’s common stock to the stockholders of Southwestern in connection with the Southwestern Merger, and Southwestern’s stockholders approved the Merger Agreement.

On October 1, 2024, the Southwestern Merger was completed, and we issued approximately 95.7 million shares of our common stock to Southwestern’s shareholders in connection with the Merger Agreement. Under the terms of the Merger Agreement, subject to certain exceptions, each share of Southwestern common stock was converted into the right to receive 0.0867 of a share of the Company’s common stock. Based on the closing price of our common stock, the total value of the shares of our common stock issued to Southwestern’s shareholders was approximately $7.9 billion. During 2025, we recognized approximately $57 million of costs related to the Southwestern Merger, which primarily consisted of employee expenses. During 2024, we recognized approximately $312 million of costs related to the Southwestern Merger, which included $148 million related to employee expenses and the remainder of the costs relating to transaction fees, consulting and legal fees and other fees related to the transaction. These acquisition-related costs are included within other operating expense, net within our consolidated statements of operations. The Southwestern Merger was structured as a tax-free reorganization for United States federal income tax purposes.

Southwestern Merger Purchase Price Allocation

We have accounted for the Southwestern Merger as a business combination, using the acquisition method, with Expand Energy (formerly Chesapeake) treated as the accounting acquirer. During 2025, we finalized the acquisition accounting for this transaction. The following table represents the allocation of the total purchase price of Southwestern to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.


	Purchase Price Allocation
Consideration:
Cash(a)	$	585
Fair value of Expand Energy common stock issued(b)	7,871
Restricted stock unit and performance stock unit replacement awards	17
Total consideration	$	8,473

Fair Value of Assets Acquired:
Cash and cash equivalents and restricted cash	$	126
Other current assets	828
Proved natural gas and oil properties	10,002
Unproved properties	4,270
Other property and equipment	128
Other long-term assets	496
Amounts attributable to assets acquired	$	15,850

Fair Value of Liabilities Assumed:
Current liabilities	$	1,955
Long-term debt	3,305
Deferred tax liabilities	479
Long-term contract liabilities	1,287
Other long-term liabilities	351
Amounts attributable to liabilities assumed	$	7,377

Total identifiable net assets	$	8,473

____________________________________________

(a)Reflects the repayment of $585 million outstanding on Southwestern's 2022 revolving credit facility including $2 million of accrued interest and fees, as the facility was repaid and retired upon close of the Southwestern Merger.

(b)The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.

Natural Gas and Oil Properties

For the Southwestern Merger, we applied the business combination guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets.

The inputs used to value natural gas and oil properties require significant judgment and estimates made by management and represent Level 3 inputs.

As part of the Southwestern Merger, we assumed gathering, processing and transportation contracts, certain of which were deemed to be above or below current market rates. We recognized assets and liabilities for the difference in the contractual and market rates of these contracts, as of the date of the Merger. The terms of the contracts extend through 2035.

Southwestern Merger Revenues and Expenses Subsequent to Acquisition

We included in our consolidated statements of operations natural gas, oil and NGL revenues of $1,021 million, marketing revenues of $482 million, net losses on natural gas, oil and NGL derivatives of $34 million, and direct operating expenses of $1,384 million, including depreciation, depletion and amortization, and net earnings of $36 million, related to the Southwestern Merger businesses for the period from October 1, 2024 through December 31, 2024.

Combined Pro Forma Financial Information

As the Southwestern Merger closed on October 1, 2024, all activity in 2025 is included in our consolidated statements of operations. The following unaudited pro forma financial information is based on our historical consolidated financial statements adjusted to reflect as if the Southwestern Merger and the divestiture of our Eagle Ford assets had each occurred on January 1, 2023. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments.


	Years Ended December 31,
	2024		2023
Revenues	$	8,193	$	14,247
Net income (loss) available to common stockholders	$	(607)	$	3,852
Earnings (loss) per common share:
Basic	$	(2.65)	$	16.86
Diluted	$	(2.65)	$	16.14

Eagle Ford Divestitures

During 2023, we divested our Eagle Ford assets through three separate transactions (“the Eagle Ford divestiture transactions”), for approximately $3.5 billion, subject to customary post-closing adjustments. In each of these transactions, we received a portion of the purchase price upon closing, subject to customary post-closing adjustments, with the remainder of the purchase price recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments in up to the following four years following the close of the transaction. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $114 million and $114 million of the deferred consideration is reflected within other current assets and approximately $91 million and $188 million of the deferred consideration is reflected within other long-term assets on the consolidated balance sheets as of December 31, 2025 and December 31, 2024, respectively. Additionally, during 2024, we received a contingent payment of $25 million related to one of the Eagle Ford divestiture transactions, based upon the average NYMEX prices during the year following the close of the transaction. These installment payments are recorded as receipts of deferred consideration in our consolidated statements of cash flows. The contingent payment noted above was recorded as cash receipts on derivative settlements, net in our consolidated statements of cash flows. The Eagle Ford divestiture transactions, resulted in an aggregate gain of approximately $947 million, inclusive of post-closing adjustments, based on the difference between the carrying value of the assets and consideration received.

During the years ended December 31, 2025, 2024 and 2023, we amortized approximately $19 million, $31 million and $24 million, respectively, related to the deferred consideration from the Eagle Ford divestiture transactions described above. The deferred consideration amortization is recorded within other income, net, in our consolidated statements of operations.

Investments

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

Investments


15.			Investments

Momentum Sustainable Ventures LLC. During the fourth quarter of 2022, the Company entered into an agreement with Momentum Sustainable Ventures LLC (“Momentum”) to build a new natural gas gathering pipeline and carbon capture project, which gathers and treats natural gas produced in the Haynesville Shale for delivery to Gulf Coast markets, including LNG export, the New Generation Gas Gathering LLC (“NG3” operated pipeline) (the “NG3 pipeline”). The NG3 pipeline was placed in service and began gathering operations on October 1, 2025. Under a CO2 services agreement with ExxonMobil Low Carbon Solutions Onshore Storage, LLC (“Exxon”), NG3 anticipates that it will deliver CO2 to Exxon for capture, additional transportation and storage. We have a 35% interest in the joint venture entity and classify our investment with Momentum in the NG3 pipeline as a related party.

We have accounted for this investment as an equity method investment, and its carrying value, which is reflected within other long-term assets on the consolidated balance sheets, was $313 million and $307 million as of December 31, 2025 and December 31, 2024, respectively. As of December 31, 2025, the carrying value of our investment included approximately $29 million of capitalized interest related to the project. We recognize our proportionate share of income (loss) related to our investment with Momentum in other income, net within our consolidated statements of operations. Our proportionate share of income (loss) related to our investment with Momentum is recognized on a three-month lag and during the years ended December 31, 2025, 2024 and 2023, our proportionate share of income (loss) related our investment in the NG3 pipeline did not have a material impact to our financial statements. We periodically review our investment with Momentum to determine if a loss in value, which is other than a temporary decline, has occurred. If an other than temporary decline has occurred, we recognize an impairment on our investment. Through December 31, 2025, we have not recognized any impairments related to our investment with Momentum.

The NG3 pipeline provides to us certain gathering, processing and transportation services. We have a gathering agreement in which approximately 900 MMcf per day, on average, of natural gas are to be gathered and processed by the NG3 pipeline over the course of the next 12 years. During the year ended December 31, 2025, approximately $15 million of our gathering, processing and transportation expenses were related to services provided by the NG3 pipeline, and is reflected within our consolidated statements of operations. Additionally, approximately $12 million of our accounts payable balance as of December 31, 2025 was related gathering, processing and transportation services rendered to us by the NG3 pipeline.

Supplemental Cash Flow Information - Income Taxes Paid (Refunds Received), Net by State (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	$ (14)	$ (10)	$ 12
Louisiana
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	(15)	(1)	12
New York
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	1	0	0
Pennsylvania
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	(1)	(10)	0
Texas
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	0	2	0
West Virginia
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	1	0	0
Other states
Other Significant Noncash Transactions [Line Items]
Income taxes paid (refunds received)	$ 0	$ (1)	$ 0

Debt - Narrative (Details)		1 Months Ended		3 Months Ended	12 Months Ended
Debt - Narrative (Details)	Oct. 01, 2024 USD ($)	Mar. 31, 2025 USD ($)	Jan. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2025 USD ($) extension_term	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 02, 2024 USD ($)	Oct. 28, 2024 USD ($)
Debt Instrument [Line Items]
Outstanding borrowings					$ 5,025,000,000
Repayments of debt					663,000,000	$ 767,000,000	$ 0
Credit facility
Debt Instrument [Line Items]
Extinguishment of debt	$ 585,000,000
Secured debt
Debt Instrument [Line Items]
Outstanding borrowings					$ 0
2025 Credit Facility \| Credit facility
Debt Instrument [Line Items]
Debt instrument extension term \| extension_term					2
Debt instrument, term					1 year
2025 Credit Facility \| Credit facility \| Federal Funds Effective Rate
Debt Instrument [Line Items]
Basis spread on variable rate					0.50%
2025 Credit Facility \| Credit facility \| Secured Overnight Financing Rate (SOFR)
Debt Instrument [Line Items]
Basis spread on variable rate					1.00%
2025 Credit Facility \| Credit facility \| Maximum
Debt Instrument [Line Items]
Ratio of indebtedness to net capital					0.65
2025 Credit Facility \| Credit facility \| Maximum \| Secured Overnight Financing Rate (SOFR)
Debt Instrument [Line Items]
Basis spread on variable rate					1.00%
2025 Credit Facility \| Credit facility \| Minimum \| Secured Overnight Financing Rate (SOFR)
Debt Instrument [Line Items]
Basis spread on variable rate					0.125%
Revolving Credit Facility \| Credit facility
Debt Instrument [Line Items]
Maximum borrowing capacity				$ 2,500,000,000	$ 3,500,000,000	2,500,000,000
Unused borrowing capacity					$ 3,500,000,000
Revolving Credit Facility \| Credit facility \| Maximum
Debt Instrument [Line Items]
Basis spread on variable rate					2.00%
Unused capacity, commitment fee percentage					0.325%
Revolving Credit Facility \| Credit facility \| Minimum
Debt Instrument [Line Items]
Basis spread on variable rate					1.125%
Unused capacity, commitment fee percentage					0.125%
Revolving Credit Facility \| Credit facility \| Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity				500,000,000	$ 1,000,000,000	500,000,000
Revolving Credit Facility \| Credit facility \| Swingline Loans
Debt Instrument [Line Items]
Maximum borrowing capacity				50,000,000	100,000,000	50,000,000
Revolving Credit Facility \| Credit facility \| Plan
Debt Instrument [Line Items]
Increase in maximum borrowing capacity					$ 1,000,000,000
4.95% senior notes due 2025 \| Senior notes
Debt Instrument [Line Items]
Debt, principal	$ 389,000,000
Interest rate, stated percentage	4.95%				4.95%
Extinguishment of debt			$ 389,000,000
Outstanding borrowings				389,000,000	$ 0	389,000,000
8.375% senior notes due 2028 \| Senior notes
Debt Instrument [Line Items]
Debt, principal	$ 304,000,000			304,000,000		304,000,000
Interest rate, stated percentage	8.375%
Repayments of debt				312,000,000
Premium				8,000,000
5.375% senior notes due 2029 \| Senior notes
Debt Instrument [Line Items]
Debt, principal	$ 700,000,000
Interest rate, stated percentage	5.375%				5.375%
Extinguishment of debt					$ 62,000,000
Outstanding borrowings				700,000,000	$ 638,000,000	700,000,000
5.375% senior notes due 2030 \| Senior notes
Debt Instrument [Line Items]
Debt, principal	$ 1,200,000,000
Interest rate, stated percentage	5.375%				5.375%
Outstanding borrowings				1,200,000,000	$ 1,200,000,000	1,200,000,000
4.75% senior notes due 2032 \| Senior notes
Debt Instrument [Line Items]
Debt, principal	$ 1,150,000,000
Interest rate, stated percentage	4.75%				4.75%
Outstanding borrowings				1,150,000,000	$ 1,150,000,000	1,150,000,000
5.70% senior notes due 2035 \| Senior notes
Debt Instrument [Line Items]
Debt, principal								$ 750,000,000
Interest rate, stated percentage					5.70%			5.70%
Outstanding borrowings				750,000,000	$ 750,000,000	750,000,000
5.50% senior notes due 2026 \| Senior notes
Debt Instrument [Line Items]
Debt, principal									$ 500,000,000
Interest rate, stated percentage		5.50%			5.50%				5.50%
Extinguishment of debt		$ 47,000,000
Outstanding borrowings				$ 47,000,000	$ 0	47,000,000
Percentage of principal amount redeemed				91.00%
Repayments of debt				$ 453,000,000
5.875% senior notes due 2029 \| Senior notes
Debt Instrument [Line Items]
Debt, principal									$ 500,000,000
Interest rate, stated percentage					5.875%				5.875%
Extinguishment of debt					$ 60,000,000
Outstanding borrowings				500,000,000	$ 440,000,000	500,000,000
6.75% senior notes due 2029 \| Senior notes
Debt Instrument [Line Items]
Debt, principal									$ 950,000,000
Interest rate, stated percentage	6.75%				6.75%				6.75%
Extinguishment of debt					$ 103,000,000
Outstanding borrowings				$ 950,000,000	$ 847,000,000	$ 950,000,000

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Components of the Income Tax Expense (Benefit)

The components of the income tax expense (benefit) for each of the periods presented below are as follows:


	Years Ended December 31,
	2025		2024		2023
Current Tax Expense (Benefit)
US Federal	$	8	$	(1)	$	264
US State and Local	7		(3)		6
Total Current Tax Expense (Benefit)	15		(4)		270
Deferred Tax Expense (Benefit)
US Federal	410		(178)		381
US State and Local	38		55		47
Total Deferred Tax Expense (Benefit)	448		(123)		428
Total Income Tax Expense (Benefit)
US Federal	418		(179)		645
US State and Local	45		52		53
Total Income Tax Expense (Benefit)	$	463	$	(127)	$	698

Schedule of Effective Income Tax Expense (Benefit)

The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate for the following reasons:


	Years Ended December 31,
	2025				2024				2023
U.S. Federal Statutory Tax Rate	$	479	21.0	%	$	(177)	21.0	%	$	655	21.0	%
State and Local Income Taxes, Net of Federal Income Tax Effect(a)	42		1.8	%	29		(3.4)	%	51		1.6	%

Tax credits
Research and development tax credits	(46)		(2.0)	%	(32)		3.8	%	(10)		(0.3)	%
Changes in Valuation Allowances	11		0.5	%	9		(1.1)	%	(28)		(0.9)	%
Nontaxable or nondeductible items
Merger Related Costs	(21)		(0.9)	%	33		(3.9)	%	—		—	%
Other	3		0.1	%	1		(0.1)	%	3		0.1	%
Changes in Unrecognized Tax Benefits	—		—	%	—		—	%	6		0.2	%
Other adjustments
Return to provision	(35)		(1.5)	%	—		—	%	(16)		(0.5)	%
Capital loss expirations	30		1.3	%	5		(0.6)	%	26		0.8	%
Other	—		—	%	5		(0.6)	%	11		0.4	%
Effective Tax Rate	$	463	20.3	%	$	(127)	15.1	%	$	698	22.4	%

_________________________________________

(a)State taxes in Louisiana, Pennsylvania and West Virginia made up the majority (greater than 50 percent) of the tax effect in this category.

Schedule of Deferred Tax Assets and Liabilities

The tax-effected temporary differences, net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows:


	December 31, 2025		December 31, 2024
Deferred tax liabilities:
Property, plant and equipment	$	(2,250)	$	(1,730)
Derivative instruments	(72)		—
Investments	(82)		—
Contracts	(71)		—
Right of use lease asset	(24)		(36)
Other	(5)		(3)
Deferred tax liabilities	(2,504)		(1,769)

Deferred tax assets:

Net operating loss carryforwards	1,613		1,258
Carrying value of debt	1		4
Excess business interest expense carryforward	654		777
Capital loss carryforwards	70		103
Tax credit carryforwards	107		53
Contract liabilities	286		261
Asset retirement obligations	169		123

Future lease payments	25		36
Accrued liabilities	22		39
Derivative instruments	—		13
Other	32		24
Deferred tax assets	2,979		2,691
Valuation allowance	(344)		(343)
Deferred tax assets after valuation allowance	2,635		2,348
Net deferred tax asset	$	131	$	579

Reflected in the accompanying balance sheets as:
Deferred income tax assets	$	168	$	589
Other long-term liabilities	(37)		(10)
Total	$	131	$	579

Schedule of Federal NOLs and Excess Business Interest

As of December 31, 2025, and after taking into account each of the foregoing matters, the federal NOLs are as follows:


Net operating losses, by year of expiration:
2031	$	9
2032	3
2033	2
2034	2
2035	79
2036	642
2037	726
Indefinitely lived	5,302
Total federal net operating losses	$	6,765

Schedule of Reconciliation of Unrecognized Tax Benefits

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


	Years Ended December 31,
	2025		2024		2023
Balance at January 1	$	80	$	68	$	69
Additions based on tax positions related to the current year	7		3		3
Additions to tax positions of prior years	1		1		3
Additions to tax positions related to acquisitions	—		9		—
Settlements	—		—		(5)

Reductions to tax positions of prior years	(24)		(1)		(2)
Balance at December 31	$	64	$	80	$	68

Income Taxes - Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current Tax Expense (Benefit)
US Federal	$ 8	$ (1)	$ 264
US State and Local	7	(3)	6
Total Current Tax Expense (Benefit)	15	(4)	270
Deferred Tax Expense (Benefit)
US Federal	410	(178)	381
US State and Local	38	55	47
Total Deferred Tax Expense (Benefit)	448	(123)	428
Total Income Tax Expense (Benefit)
US Federal	418	(179)	645
US State and Local	45	52	53
Effective Tax Rate	$ 463	$ (127)	$ 698

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues and other:
Gain (loss) on derivatives	$ 550	$ (38)	$ 1,728
Gains (losses) on sales of assets	(65)	14	946
Total revenues and other	12,124	4,235	8,721
Operating expenses:
Production	635	316	356
Gathering, processing and transportation	2,376	1,035	853
Severance and ad valorem taxes	193	97	167
Exploration	46	10	27
General and administrative	181	186	127
Separation and other termination costs	5	23	5
Depreciation, depletion and amortization	2,980	1,729	1,527
Impairments	37	0	0
Other operating expense, net	40	332	18
Total operating expenses	9,653	5,038	5,579
Income (loss) from operations	2,471	(803)	3,142
Other income (expense):
Interest expense	(235)	(123)	(104)
Gains (losses) on purchases, exchanges or extinguishments of debt	4	(1)	0
Other income, net	42	86	79
Total other income (expense)	(189)	(38)	(25)
Income (loss) before income taxes	2,282	(841)	3,117
Income tax expense (benefit)	463	(127)	698
Net income (loss)	$ 1,819	$ (714)	$ 2,419
Earnings (loss) per common share:
Basic (in dollars per share)	$ 7.67	$ (4.55)	$ 18.21
Diluted (in dollars per share)	$ 7.57	$ (4.55)	$ 16.92
Weighted average common shares outstanding (in thousands):
Basic (in shares)	237,290	156,989	132,840
Diluted (in shares)	240,370	156,989	142,976
Natural gas, oil and NGL
Revenues and other:
Revenues	$ 8,476	$ 2,969	$ 3,547
Marketing
Revenues and other:
Revenues	3,163	1,290	2,500
Operating expenses:
Marketing	$ 3,160	$ 1,310	$ 2,499

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Sources of Change in Standardized Measure of Discounted Future Net Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Extractive Industries [Abstract]
Standardized measure, beginning balance	$ 7,531	$ 4,477	$ 26,305
Sales of natural gas and oil produced, net of production costs and gathering processing and transportation	(5,272)	(1,521)	(2,171)
Net changes in prices and production costs	11,359	(2,266)	(23,535)
Extensions and discoveries, net of production and development costs	19	50	182
Changes in estimated future development costs	(2,316)	652	346
Previously estimated development costs incurred during the period	827	396	818
Revisions of previous quantity estimates	7,109	(922)	(205)
Purchase of reserves-in-place	0	5,409	77
Sales of reserves-in-place	0	0	(7,158)
Accretion of discount	757	457	3,270
Net change in income taxes	(2,213)	58	6,301
Changes in production rates and other	(675)	741	247
Standardized measure, ending balance	$ 17,126	$ 7,531	$ 4,477

Natural Gas and Oil Property Transactions (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Purchase Price Allocation


	Purchase Price Allocation
Consideration:
Cash(a)	$	585
Fair value of Expand Energy common stock issued(b)	7,871
Restricted stock unit and performance stock unit replacement awards	17
Total consideration	$	8,473

Fair Value of Assets Acquired:
Cash and cash equivalents and restricted cash	$	126
Other current assets	828
Proved natural gas and oil properties	10,002
Unproved properties	4,270
Other property and equipment	128
Other long-term assets	496
Amounts attributable to assets acquired	$	15,850

Fair Value of Liabilities Assumed:
Current liabilities	$	1,955
Long-term debt	3,305
Deferred tax liabilities	479
Long-term contract liabilities	1,287
Other long-term liabilities	351
Amounts attributable to liabilities assumed	$	7,377

Total identifiable net assets	$	8,473

____________________________________________

(b)The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.

Schedule of Pro Forma Financial Information

The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments.


	Years Ended December 31,
	2024		2023
Revenues	$	8,193	$	14,247
Net income (loss) available to common stockholders	$	(607)	$	3,852
Earnings (loss) per common share:
Basic	$	(2.65)	$	16.86
Diluted	$	(2.65)	$	16.14

- Definition

Tabular disclosure of business combination. Includes, but is not limited to, recognized asset and liability.

+ References + Details

Equity (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Dividends

The following table summarizes our dividend payments during the years ended December 31, 2025, 2024 and 2023:


	Base		Variable		Rate Per Share		Total
2025:
First Quarter	$	0.575	$	—	$	0.575	$	138
Second Quarter	$	0.575	$	—	$	0.575	$	138
Third Quarter	$	0.575	$	0.89	$	1.465	$	351
Fourth Quarter	$	0.575	$	—	$	0.575	$	138

2024:
First Quarter	$	0.575	$	—	$	0.575	$	77
Second Quarter	$	0.575	$	0.14	$	0.715	$	95
Third Quarter	$	0.575	$	—	$	0.575	$	78
Fourth Quarter	$	0.575	$	—	$	0.575	$	134

2023:
First Quarter	$	0.55	$	0.74	$	1.29	$	175
Second Quarter	$	0.55	$	0.63	$	1.18	$	160
Third Quarter	$	0.575	$	—	$	0.575	$	77
Fourth Quarter	$	0.575	$	—	$	0.575	$	75

Schedule of Warrants

Warrants


	Class A Warrants	Class B Warrants	Class C Warrants(a)
Outstanding as of December 31, 2022	4,495,004	4,404,564	4,006,229
Converted into common stock(b)	(247,389)	(1,500)	(5,581)

Issued for General Unsecured Claims	—	—	22,835
Outstanding as of December 31, 2023	4,247,615	4,403,064	4,023,483
Converted into common stock(b)	(2,993,136)	(1,329,870)	(524,242)
Issued for General Unsecured Claims	—	—	884,393
Outstanding as of December 31, 2024	1,254,479	3,073,194	4,383,634
Converted into common stock(b)	(1,238,774)	(3,024,393)	(3,696,720)
Issued for General Unsecured Claims	—	—	557,094
Outstanding as of December 31, 2025	15,705	48,801	1,244,008

_________________________________________

(a)As of December 31, 2025, we had 25,015 of reserved Class C Warrants.

(b)During the years ended December 31, 2025, 2024 and 2023, we issued 7,497,509, 4,083,103 and 221,952 common shares, respectively, as a result of Warrant exercises.

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Changes in Estimated Reserves (Details)	12 Months Ended
	Dec. 31, 2025 Bcfe Bcf MMBbls	Dec. 31, 2024 Bcfe Bcf MMBbls	Dec. 31, 2023 Bcfe Bcf MMBbls
Oil and Gas, Proved Reserve, Quantity, Energy [Roll Forward]
Proved reserves, beginning of period (Energy) \| Bcfe	20,800	9,688	13,002
Extensions, discoveries and other additions \| Bcfe	52	124	415
Revisions of previous estimates \| Bcfe	7,650	(1,654)	(325)
Production \| Bcfe	(2,622)	(1,375)	(1,335)
Sale of reserves-in-place \| Bcfe	0	0	(2,127)
Purchase of reserves-in-place \| Bcfe	0	14,017	58
Proved reserves, ending of period (Energy) \| Bcfe	25,880	20,800	9,688
Proved developed reserves, Beginning of period (Energy) \| Bcfe	16,958	6,363	8,681
Proved developed reserves, Ending of period (Energy) \| Bcfe	18,576	16,958	6,363
Proved undeveloped reserves, Beginning of period (Energy) \| Bcfe	3,842	3,325	4,321
Proved undeveloped reserves, Ending of period (Energy) \| Bcfe	7,304	3,842	3,325
Natural Gas
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]
Proved reserves, beginning of period \| Bcf	16,924	9,688	11,369
Extensions, discoveries and other additions \| Bcf	52	124	415
Revisions of previous estimates \| Bcf	8,008	(1,654)	(325)
Production \| Bcf	(2,409)	(1,321)	(1,266)
Sale of reserves-in-place \| Bcf	0	0	(563)
Purchase of reserves-in-place \| Bcf	0	10,087	58
Proved reserves, ending of period \| Bcf	22,575	16,924	9,688
Oil and Gas, Proved Reserve, Quantity, Energy [Roll Forward]
Proved developed reserves, Beginning of period \| Bcf	14,418	6,363	7,385
Proved developed reserves, Ending of period \| Bcf	16,395	14,418	6,363
Proved undeveloped reserves, Beginning of period \| Bcf	2,506	3,325	3,984
Proved undeveloped reserves, Ending of period \| Bcf	6,180	2,506	3,325
Oil
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]
Proved reserves, beginning of period	67.9	0	198.4
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	(3.2)	0	0
Production	(5.9)	(1.2)	(7.7)
Sale of reserves-in-place	0	0	(190.7)
Purchase of reserves-in-place	0	69.1	0
Proved reserves, ending of period	58.8	67.9	0
Oil and Gas, Proved Reserve, Quantity, Energy [Roll Forward]
Proved developed reserves, Beginning of period	40.3	0	157.2
Proved developed reserves, Ending of period	35.0	40.3	0
Proved undeveloped reserves, Beginning of period	27.6	0	41.2
Proved undeveloped reserves, Ending of period	23.8	27.6	0
NGL
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]
Proved reserves, beginning of period	578.1	0	73.9
Extensions, discoveries and other additions	0	0	0
Revisions of previous estimates	(56.6)	0	0
Production	(29.6)	(7.8)	(3.8)
Sale of reserves-in-place	0	0	(70.1)
Purchase of reserves-in-place	0	585.9	0
Proved reserves, ending of period	491.9	578.1	0
Oil and Gas, Proved Reserve, Quantity, Energy [Roll Forward]
Proved developed reserves, Beginning of period	383.0	0	58.9
Proved developed reserves, Ending of period	328.5	383.0	0
Proved undeveloped reserves, Beginning of period	195.1	0	15.0
Proved undeveloped reserves, Ending of period	163.4	195.1	0

Employee Benefit Plans (Details) - USD ($)	12 Months Ended
Employee Benefit Plans (Details) - USD ($)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discretionary contribution, percent of adjusted free cash flow	1.00%
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer annual maximum contribution amount	$ 15,000
Expand Energy Corporation 401(k) Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contribution amount	$ 25,000,000	$ 8,000,000	$ 13,000,000
Expand Energy Corporation 401(k) Plan \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution	6.00%

Natural Gas and Oil Property Transactions - Narrative (Details) shares in Millions, $ in Millions		3 Months Ended	12 Months Ended
	Oct. 01, 2024 USD ($) shares	Dec. 31, 2024 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($) transaction
Business Combination [Line Items]
Gain (loss) on derivatives			$ 550	$ (38)	$ 1,728
Costs and expenses			9,653	5,038	5,579
Net income (loss)			1,819	(714)	2,419
Disposal group, disposed of by sale, not discontinued operations
Business Combination [Line Items]
Deferred consideration amortization			19	31	$ 24
Eagle Ford divestiture \| Disposal group, disposed of by sale, not discontinued operations
Business Combination [Line Items]
Number of assets divestiture transactions \| transaction					3
Consideration received		$ 25		25	$ 3,500
Payment period					4 years
Gain (loss) on sale of oil and natural gas properties					$ 947
Eagle Ford divestiture \| Disposal group, disposed of by sale, not discontinued operations \| Short-term derivative asset
Business Combination [Line Items]
Deferred consideration reflected with assets		114	114	114
Eagle Ford divestiture \| Disposal group, disposed of by sale, not discontinued operations \| Long-term derivative asset
Business Combination [Line Items]
Deferred consideration reflected with assets		188	91	188
Natural gas, oil and NGL
Business Combination [Line Items]
Revenues			8,476	2,969	3,547
Marketing
Business Combination [Line Items]
Revenues			3,163	1,290	$ 2,500
Southwestern
Business Combination [Line Items]
Common stock issued for acquisition (in shares) \| shares	95.7
Share conversion ratio	0.0867
Total value of common stock issued	$ 7,900
Acquisition related costs			$ 57	312
Employee related expenses				$ 148
Gain (loss) on derivatives		(34)
Costs and expenses		1,384
Net income (loss)		36
Southwestern \| Natural gas, oil and NGL
Business Combination [Line Items]
Revenues		1,021
Southwestern \| Marketing
Business Combination [Line Items]
Revenues		$ 482

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value, vested	$ 58	$ 77	$ 25
Unrecognized compensation expense	$ 58
Share-based compensation expense, weighted average period for recognition	1 year 11 months 4 days
Restricted Stock Units (RSUs) \| Employee \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Restricted Stock Units (RSUs) \| Employee \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	5 years	5 years	5 years
Restricted Stock Units (RSUs) \| Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year	1 year	1 year
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value, vested	$ 22	$ 19
Unrecognized compensation expense	$ 26
Share-based compensation expense, weighted average period for recognition	2 years 10 days
Performance shares \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return and relative total shareholder return, percent of payout of target units	0.00%	0.00%	0.00%
Performance shares \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shareholder return and relative total shareholder return, percent of payout of target units	200.00%	200.00%	200.00%
Performance shares \| Management
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
2021 Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, reserved for future issuance (in shares)	6,800,000

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock	Additional Paid-in Capital	Retained Earnings
Beginning balance (in shares) at Dec. 31, 2022		134,715,094
Beginning balance at Dec. 31, 2022	$ 9,124	$ 1	$ 5,724	$ 3,399
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)		214,684
Share-based compensation	31		31
Issuance of common stock for warrant exercise (in shares)		221,952
Issuance of reserved common stock and warrants (in shares)		12,089
Repurchase and retirement of common stock (in shares)		(4,373,883)
Repurchase and retirement of common stock	(358)		(1)	(357)
Net income (loss)	2,419			2,419
Dividends on common stock	(487)			(487)
Ending balance (in shares) at Dec. 31, 2023		130,789,936
Ending balance at Dec. 31, 2023	10,729	$ 1	5,754	4,974
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock for Southwestern Merger (in shares)		95,700,325
Issuance of common stock for Southwestern Merger	7,889	$ 1	7,888
Share-based compensation (in shares)		727,799
Share-based compensation	42		42
Issuance of common stock for warrant exercise (in shares)		4,083,103
Issuance of common stock for warrant exercise	3		3
Issuance of reserved common stock and warrants (in shares)		468,723
Net income (loss)	(714)			(714)
Dividends on common stock	(384)			(384)
Ending balance (in shares) at Dec. 31, 2024		231,769,886
Ending balance at Dec. 31, 2024	17,565	$ 2	13,687	3,876
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation (in shares)		538,885
Share-based compensation	35		35
Issuance of common stock for warrant exercise (in shares)		7,497,509
Issuance of common stock for warrant exercise	24		24
Issuance of reserved common stock and warrants (in shares)		295,255
Repurchase and retirement of common stock (in shares)		(851,661)
Repurchase and retirement of common stock	(100)			(100)
Net income (loss)	1,819			1,819
Dividends on common stock	(765)			(765)
Ending balance (in shares) at Dec. 31, 2025		239,249,874
Ending balance at Dec. 31, 2025	$ 18,578	$ 2	$ 13,746	$ 4,830

Debt - Debt Maturities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Disclosure [Abstract]
2029	$ 1,925
2030	1,200
Thereafter	1,900
Total debt	$ 5,025

Equity

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Equity


10.			Equity

Common Stock

On October 1, 2024, we issued 95,700,325 shares of our common stock to Southwestern’s shareholders in connection with the closing of the Southwestern Merger. See further discussion in Note 2.

During the years ended December 31, 2025, 2024 and 2023, 295,255, 468,723 and 12,089 reserved shares, respectively, were issued to resolve allowed General Unsecured Claims.

Dividends

In May 2021, we initiated an annual base dividend on our shares of common stock, expected to be paid quarterly. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. In 2025, we prioritized paying a base dividend per share and provided for annual net debt reduction prior to additional shareholder returns such as additional dividend payments or share repurchases. The following table summarizes our dividend payments during the years ended December 31, 2025, 2024 and 2023:


	Base		Variable		Rate Per Share		Total
2025:
First Quarter	$	0.575	$	—	$	0.575	$	138
Second Quarter	$	0.575	$	—	$	0.575	$	138
Third Quarter	$	0.575	$	0.89	$	1.465	$	351
Fourth Quarter	$	0.575	$	—	$	0.575	$	138

2024:
First Quarter	$	0.575	$	—	$	0.575	$	77
Second Quarter	$	0.575	$	0.14	$	0.715	$	95
Third Quarter	$	0.575	$	—	$	0.575	$	78
Fourth Quarter	$	0.575	$	—	$	0.575	$	134

2023:
First Quarter	$	0.55	$	0.74	$	1.29	$	175
Second Quarter	$	0.55	$	0.63	$	1.18	$	160
Third Quarter	$	0.575	$	—	$	0.575	$	77
Fourth Quarter	$	0.575	$	—	$	0.575	$	75

On February 17, 2026, we declared a base quarterly dividend payable of $0.575 per share which will be paid on March 26, 2026 to stockholders of record at the close of business on March 5, 2026.

Share Repurchase Programs

As of December 2, 2021, the Company was authorized to purchase up to $1.0 billion of the Company’s common stock and/or warrants under a share repurchase program, and in March 2022, we commenced our share repurchase program. In June 2022, our Board of Directors authorized an expansion of the share repurchase program by $1.0 billion, bringing the total authorized share repurchase amount to $2.0 billion for common stock and/or warrants. Under the $2.0 billion share repurchase program, we repurchased approximately 4.4 million shares for an aggregate price of approximately $357 million during the year ended December 31, 2023. The $2.0 billion share repurchase program expired on December 31, 2023.

On October 22, 2024, our Board of Directors authorized repurchases of up to $1.0 billion, in aggregate, of the Company’s common stock and/or warrants under a new share repurchase program. Under this $1.0 billion share repurchase program, we repurchased 0.9 million shares for an aggregate price of $100 million during the year ended December 31, 2025. We did not repurchase any shares during the year ended December 31, 2024.

The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings. All share repurchases made after January 1, 2023 are subject to a 1% excise tax on share repurchases, as enacted under the Inflation Reduction Act of 2022. We are able to net this 1% excise tax on share repurchases against certain issuance of shares of our common stock. To date, the impact of this 1% excise tax has been immaterial.

Warrants


	Class A Warrants	Class B Warrants	Class C Warrants(a)
Outstanding as of December 31, 2022	4,495,004	4,404,564	4,006,229
Converted into common stock(b)	(247,389)	(1,500)	(5,581)

Issued for General Unsecured Claims	—	—	22,835
Outstanding as of December 31, 2023	4,247,615	4,403,064	4,023,483
Converted into common stock(b)	(2,993,136)	(1,329,870)	(524,242)
Issued for General Unsecured Claims	—	—	884,393
Outstanding as of December 31, 2024	1,254,479	3,073,194	4,383,634
Converted into common stock(b)	(1,238,774)	(3,024,393)	(3,696,720)
Issued for General Unsecured Claims	—	—	557,094
Outstanding as of December 31, 2025	15,705	48,801	1,244,008

_________________________________________

(a)As of December 31, 2025, we had 25,015 of reserved Class C Warrants.

(b)During the years ended December 31, 2025, 2024 and 2023, we issued 7,497,509, 4,083,103 and 221,952 common shares, respectively, as a result of Warrant exercises.

Our Class A, Class B and Class C Warrants were initially exercisable for one share of common stock per Warrant at initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively, subject to adjustments pursuant to the terms of the Warrants. The Warrants were exercisable until February 9, 2026. The Warrants contained customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. The exercise prices of the Warrants were adjusted to prevent the dilution of rights for the effects of the quarterly dividend distribution on December 4, 2025, and the adjusted exercise prices are $21.89, $25.45, and $28.66 per share for the Class A, Class B and Class C Warrants, respectively. Additionally, we have recalculated the number of shares of common stock issuable upon the exercise of each of the Class A, Class B and Class C Warrants, respectively, and as a result, 1.22 shares are issuable upon the exercise of a Class A, Class B or Class C Warrant.

At February 9, 2026, all of the outstanding Warrants had been exercised or expired. As a result of these Warrant exercises, we issued 1,122,179 common shares and no longer have any outstanding Warrants.

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
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-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
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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 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 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	239,249,874	231,769,886

Contingencies and Commitments (Tables)

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Schedule of Contractual Obligation


	December 31, 2025
2026	$	1,428
2027	1,337
2028	1,221
2029	1,019
2030	884
Thereafter	3,683
Total	$	9,572

Other Liabilities

12 Months Ended

Dec. 31, 2025

Other Liabilities Disclosure [Abstract]

Other Liabilities


6.			Other Liabilities

Other current liabilities as of December 31, 2025 and 2024 are detailed below:


	December 31, 2025		December 31, 2024
Revenues and royalties due to others	$	972	$	734
Accrued drilling and production costs	350		296

Accrued compensation and benefits	107		124
Taxes payable	157		142
Operating leases	51		71
Joint interest prepayments received	11		13
Contract liabilities	253		284
Other	144		122
Total other current liabilities	$	2,045	$	1,786

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes


9.			Income Taxes

The components of the income tax expense (benefit) for each of the periods presented below are as follows:


	Years Ended December 31,
	2025		2024		2023
Current Tax Expense (Benefit)
US Federal	$	8	$	(1)	$	264
US State and Local	7		(3)		6
Total Current Tax Expense (Benefit)	15		(4)		270
Deferred Tax Expense (Benefit)
US Federal	410		(178)		381
US State and Local	38		55		47
Total Deferred Tax Expense (Benefit)	448		(123)		428
Total Income Tax Expense (Benefit)
US Federal	418		(179)		645
US State and Local	45		52		53
Total Income Tax Expense (Benefit)	$	463	$	(127)	$	698


	Years Ended December 31,
	2025				2024				2023
U.S. Federal Statutory Tax Rate	$	479	21.0	%	$	(177)	21.0	%	$	655	21.0	%
State and Local Income Taxes, Net of Federal Income Tax Effect(a)	42		1.8	%	29		(3.4)	%	51		1.6	%

Tax credits
Research and development tax credits	(46)		(2.0)	%	(32)		3.8	%	(10)		(0.3)	%
Changes in Valuation Allowances	11		0.5	%	9		(1.1)	%	(28)		(0.9)	%
Nontaxable or nondeductible items
Merger Related Costs	(21)		(0.9)	%	33		(3.9)	%	—		—	%
Other	3		0.1	%	1		(0.1)	%	3		0.1	%
Changes in Unrecognized Tax Benefits	—		—	%	—		—	%	6		0.2	%
Other adjustments
Return to provision	(35)		(1.5)	%	—		—	%	(16)		(0.5)	%
Capital loss expirations	30		1.3	%	5		(0.6)	%	26		0.8	%
Other	—		—	%	5		(0.6)	%	11		0.4	%
Effective Tax Rate	$	463	20.3	%	$	(127)	15.1	%	$	698	22.4	%

_________________________________________

(a)State taxes in Louisiana, Pennsylvania and West Virginia made up the majority (greater than 50 percent) of the tax effect in this category.

In 2025, the Company’s overall effective tax rate increased compared to 2024 due to the prior year’s deferred remeasurement due to Louisiana law change and also the impact of the merger costs. Due to the prior year pre-tax loss, these items caused the effective tax rate to be lower than the statutory national rate. The Company’s effective tax rate in 2024 decreased from 2023 due to the aforementioned remeasurement due to Louisiana’s law change. The return to provision adjustment in 2025 includes the impact of tax basis and attribute true ups from filing the final Southwestern tax returns during the year.

Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows:


	December 31, 2025		December 31, 2024
Deferred tax liabilities:
Property, plant and equipment	$	(2,250)	$	(1,730)
Derivative instruments	(72)		—
Investments	(82)		—
Contracts	(71)		—
Right of use lease asset	(24)		(36)
Other	(5)		(3)
Deferred tax liabilities	(2,504)		(1,769)

Deferred tax assets:

Net operating loss carryforwards	1,613		1,258
Carrying value of debt	1		4
Excess business interest expense carryforward	654		777
Capital loss carryforwards	70		103
Tax credit carryforwards	107		53
Contract liabilities	286		261
Asset retirement obligations	169		123

Future lease payments	25		36
Accrued liabilities	22		39
Derivative instruments	—		13
Other	32		24
Deferred tax assets	2,979		2,691
Valuation allowance	(344)		(343)
Deferred tax assets after valuation allowance	2,635		2,348
Net deferred tax asset	$	131	$	579

Reflected in the accompanying balance sheets as:
Deferred income tax assets	$	168	$	589
Other long-term liabilities	(37)		(10)
Total	$	131	$	579

As of December 31, 2025 and 2024, we had deferred tax assets of $2.979 billion and $2.691 billion, respectively, upon which we had a valuation allowance of $344 million and $343 million, respectively.

We maintain a partial valuation allowance of $344 million against a portion of our federal and state deferred tax assets such as NOLs, credit carryovers, and capital losses, which may expire before we are able to utilize them due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.

Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of such attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity result in a cumulative shift of more than 50% in the beneficial ownership of our stock during any three-year testing period (an “Ownership Change”).

The Company experienced an Ownership Change in 2021 and as a result of the Southwestern Merger on October 1, 2024. As a result, certain limitations apply to our NOL carryforwards, disallowed business interest

carryforwards and general business credits. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change. Accordingly, our deferred tax asset position is reflective of such limitations.

On October 1, 2024, we completed the Southwestern Merger. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in Southwestern’s assets and liabilities. We recorded a $479 million net deferred tax liability determined through business combination accounting. Additionally, we acquired NOL and interest expense carryforwards which were previously subject to base annual Section 382 limitations of $2 million and $48 million. The acquired NOL and interest expense carryforwards that were not previously subject to a base annual Section 382 limitation are now subject to a base annual Section 382 limitation of approximately $269 million as a result of the merger. The base annual limitation is estimated to be increased over the first five years for recognized built-in gains.

As of December 31, 2025, and after taking into account each of the foregoing matters, the federal NOLs are as follows:


Net operating losses, by year of expiration:
2031	$	9
2032	3
2033	2
2034	2
2035	79
2036	642
2037	726
Indefinitely lived	5,302
Total federal net operating losses	$	6,765

We had state NOL carryforwards of approximately $4.818 billion. Several states adopt the federal NOL carryforward period such that our more recent state NOLs do not expire. The state NOL carryforwards are subject to apportioned amounts of the federal Section 382 limitations.

As of December 31, 2025 and 2024, we have an income tax receivable of $83 million and $32 million included in other current assets within our consolidated balance sheets, respectively.

On July 4, 2025, the current Presidential Administration signed into law the One Big Beautiful Bill Act (the “OBBBA”). This bill restores 100% bonus depreciation for property acquired and placed into service after January 19, 2025, restores the immediate expensing of research expenditures, and provides for parity between the treatment of intangible drilling costs and depreciation for purposes of the CAMT. The enactment of the OBBBA did not impact beginning of the year deferred tax balances, as there was no change in the applicable tax rate. However, the OBBBA and its provisions contributed to a reduction in the Company’s expected current tax expense and is expected to have a material reduction to tax expense in future years.

Accounting guidance for recognizing and measuring uncertain tax positions requires a more likely than not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding recognition, classification and disclosure of uncertain tax positions. If recognized, $31 million of the uncertain tax positions identified would have an effect on the effective tax rate. As of December 31, 2025, we had $2 million accrued for interest related to these uncertain tax positions. As of December 31, 2024, we had $1 million accrued for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

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


	Years Ended December 31,
	2025		2024		2023
Balance at January 1	$	80	$	68	$	69
Additions based on tax positions related to the current year	7		3		3
Additions to tax positions of prior years	1		1		3
Additions to tax positions related to acquisitions	—		9		—
Settlements	—		—		(5)

Reductions to tax positions of prior years	(24)		(1)		(2)
Balance at December 31	$	64	$	80	$	68

Our federal and state income tax returns are subject to examination by federal and state tax authorities. Our tax years 2022 through 2025 remain open for all purposes of examination by the IRS as well as the Southwestern 2022 through 2023 returns, and the Southwestern short period return for January 1, 2024 through October 1, 2024. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization.

In addition, tax years 2022 through 2025 as well as certain earlier years remain open for examination by state tax authorities. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477617/942-740-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-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 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12C

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/740/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-21

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-17

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

+ Details

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]	We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information. We design and assess our cybersecurity risk management program guided by the NIST Cybersecurity Framework to help us identify, assess and manage cybersecurity risks relevant to our business. Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas. Our cybersecurity risk management program includes, but is not limited to, the following key elements: •risk assessments designed to help identify and address material cybersecurity risks to our critical systems and information; •a security team principally responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents; •the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security processes; •systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall and anti-virus software; •cybersecurity awareness training for our employees and contractors; •a cybersecurity incident response plan that includes procedures for responding to, escalating, and reporting cybersecurity incidents; and •a third-party risk management process for service providers, suppliers, software, and vendors who access our data and/or systems. We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected us, including our business strategy, results of operations, or financial condition. We face certain ongoing risks from cybersecurity threats that, if realized, are reasonably likely to materially affect us, including our business strategy, results of operations, or financial condition. See Item 1A. Risk Factors “Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.”
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information. We design and assess our cybersecurity risk management program guided by the NIST Cybersecurity Framework to help us identify, assess and manage cybersecurity risks relevant to our business. Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.
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]	Our Board of Directors considers cybersecurity risk as a critical part of the enterprise and its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity and other information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Board of Directors considers cybersecurity risk as a critical part of the enterprise and its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity and other information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Audit Committee receives bi-annual updates from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding any significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Members of our Board of Directors receive presentations on cybersecurity topics from information security management, internal security staff, our internal audit group and external experts as part of our Board of Directors’ continuing education on topics that impact public companies.
Cybersecurity Risk Role of Management [Text Block]	Our Audit Committee receives bi-annual updates from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding any significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Members of our Board of Directors receive presentations on cybersecurity topics from information security management, internal security staff, our internal audit group and external experts as part of our Board of Directors’ continuing education on topics that impact public companies. Our Cybersecurity Manager leads our cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Cybersecurity Manager is responsible for assessing and managing risks from cybersecurity threats and reporting significant incidents to our Cybersecurity Committee, which includes our Interim Chief Financial Officer, General Counsel and Corporate Secretary, Chief Information Officer, Cybersecurity Manager and Director of Internal Audit. Our Cybersecurity Manager has over 20 years of experience in information security and incident response and our internal cybersecurity team has over 50 years of combined experience in information security and maintains several cybersecurity certificates including but not limited to CISSP, CISM, SRISC, GSEC, and GCFE. Our Cybersecurity team regularly participates with private energy industry and federal security working groups and organizations. The members of our Cybersecurity Committee have significant experience in risk management, assessment of disclosure controls, information technology and auditing. Our management team strives to stay informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Members of our Board of Directors receive presentations on cybersecurity topics from information security management, internal security staff, our internal audit group and external experts as part of our Board of Directors’ continuing education on topics that impact public companies. Our Cybersecurity Manager leads our cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Cybersecurity Manager is responsible for assessing and managing risks from cybersecurity threats and reporting significant incidents to our Cybersecurity Committee, which includes our Interim Chief Financial Officer, General Counsel and Corporate Secretary, Chief Information Officer, Cybersecurity Manager and Director of Internal Audit. Our Cybersecurity Manager has over 20 years of experience in information security and incident response and our internal cybersecurity team has over 50 years of combined experience in information security and maintains several cybersecurity certificates including but not limited to CISSP, CISM, SRISC, GSEC, and GCFE. Our Cybersecurity team regularly participates with private energy industry and federal security working groups and organizations. The members of our Cybersecurity Committee have significant experience in risk management, assessment of disclosure controls, information technology and auditing. Our management team strives to stay informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our Cybersecurity Manager has over 20 years of experience in information security and incident response and our internal cybersecurity team has over 50 years of combined experience in information security and maintains several cybersecurity certificates including but not limited to CISSP, CISM, SRISC, GSEC, and GCFE. Our Cybersecurity team regularly participates with private energy industry and federal security working groups and organizations. The members of our Cybersecurity Committee have significant experience in risk management, assessment of disclosure controls, information technology and auditing.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our Audit Committee receives bi-annual updates from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding any significant cybersecurity incidents. Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk management program. Members of our Board of Directors receive presentations on cybersecurity topics from information security management, internal security staff, our internal audit group and external experts as part of our Board of Directors’ continuing education on topics that impact public companies. Our Cybersecurity Manager leads our cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Cybersecurity Manager is responsible for assessing and managing risks from cybersecurity threats and reporting significant incidents to our Cybersecurity Committee, which includes our Interim Chief Financial Officer, General Counsel and Corporate Secretary, Chief Information Officer, Cybersecurity Manager and Director of Internal Audit. Our Cybersecurity Manager has over 20 years of experience in information security and incident response and our internal cybersecurity team has over 50 years of combined experience in information security and maintains several cybersecurity certificates including but not limited to CISSP, CISM, SRISC, GSEC, and GCFE. Our Cybersecurity team regularly participates with private energy industry and federal security working groups and organizations. The members of our Cybersecurity Committee have significant experience in risk management, assessment of disclosure controls, information technology and auditing. Our management team strives to stay informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Derivative and Hedging Activities - Derivative Instruments (Details) - Energy related derivative $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) Bcf MMBbls	Dec. 31, 2024 USD ($) Bcf MMBbls
Derivative [Line Items]
Fair Value	$ 307	$ (54)
Natural Gas
Derivative [Line Items]
Notional Volume \| Bcf	2,484	2,199
Fair Value	$ 305	$ (49)
Natural Gas \| Fixed-price swaps
Derivative [Line Items]
Notional Volume \| Bcf	756	369
Fair Value	$ 128	$ (28)
Natural Gas \| Two-way collars
Derivative [Line Items]
Notional Volume \| Bcf	1,143	1,098
Fair Value	$ 212	$ (27)
Natural Gas \| Three-way collars
Derivative [Line Items]
Notional Volume \| Bcf	175	161
Fair Value	$ 32	$ 60
Natural Gas \| Call options \| Long
Derivative [Line Items]
Notional Volume \| Bcf	0	73
Fair Value	$ 0	$ 1
Natural Gas \| Call options \| Short
Derivative [Line Items]
Notional Volume \| Bcf	73	219
Fair Value	$ (1)	$ (16)
Natural Gas \| Basis protection swaps
Derivative [Line Items]
Notional Volume \| Bcf	337	279
Fair Value	$ (66)	$ (39)
Oil
Derivative [Line Items]
Notional Volume \| MMBbls	0	2
Fair Value	$ 2	$ 4
Oil \| Three-way collars
Derivative [Line Items]
Notional Volume \| MMBbls	0	2
Fair Value	$ 2	$ 4
NGL
Derivative [Line Items]
Notional Volume \| MMBbls	0	7
Fair Value	$ 0	$ (9)
NGL \| Fixed-price swaps
Derivative [Line Items]
Notional Volume \| MMBbls	0	7
Fair Value	$ 0	$ (9)

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2025

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information


17.			Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below.


	Years Ended December 31,
	2025		2024		2023
Changes in assets and liabilities
Accounts receivable	$	(370)	$	(168)	$	857
Accounts payable	(68)		(62)		(152)
Other current assets	(40)		3		143
Other current liabilities	193		(88)		(573)
Total	$	(285)	$	(315)	$	275

Supplemental cash flow information:
Interest paid, net of capitalized interest	$	230	$	93	$	117
Income taxes paid (refunds received), net
Federal	$	80	$	7	$	120
State(a)	$	(14)	$	(10)	$	12
Total	$	66	$	(3)	$	132

Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs	$	114	$	(49)	$	(31)
Common stock issued for business combination	$	—	$	7,888	$	—
Operating lease obligations recognized	$	39	$	137	$	96
Liabilities established in connection with property acquisitions	$	29	$	—	$	—

_________________________________________

(a)Income taxes paid (refunds received), net by state is provided below. Amounts reported within other states below include states that are individually below the reporting threshold.


	Years Ended December 31,
	2025		2024		2023
State

Louisiana	$	(15)	$	(1)	$	12
New York	1		—		—
Pennsylvania	(1)		(10)		—
Texas	—		2		—
West Virginia	1		—		—

Other states	—		(1)		—
Total	$	(14)	$	(10)	$	12

Segment Information (Details) $ in Millions	12 Months Ended
Segment Information (Details) $ in Millions	Dec. 31, 2025 USD ($) segment	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Segment Reporting [Abstract]
Number of reportable segments \| segment	1
Total assets	$ 28,287	$ 27,894
Capital expenditures	2,852	1,529	$ 1,782
Contributions to equity method investments	0	58	220
Interest revenue	$ 16	$ 45	$ 29

- Definition

Amount of asset recognized for present right to economic benefit.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
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+ Details

Earnings Per Share - Narrative (Details) - shares	12 Months Ended
Earnings Per Share - Narrative (Details) - shares	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	13,391	308,646	777,369
Class C Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	25,015	582,109	1,466,502
Warrant
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)		9,058,361
RSUs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)		315,318
PSUs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)		86,421

Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Other Property and Equipment Held for Use and Estimated Useful Lives

A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:


					Estimated Useful Life
	December 31, 2025		December 31, 2024
					(in years)
Buildings and improvements	$	135	$	329	10 - 39
Computer equipment	110		110		5
Gathering and water systems	76		78		7 - 20
Machinery and equipment	53		40		7 - 10
Land	25		29
Other	110		68		3 - 15
Total other property and equipment, at cost	509		654
Less: accumulated depreciation	(152)		(127)
Total other property and equipment, net	$	357	$	527

Leases (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Schedule of ROU Assets and Lease Liabilities

The following table presents our ROU assets and lease liabilities as of December 31, 2025 and 2024. As of December 31, 2025 and 2024, we did not have any finance leases.


	Operating Leases
	December 31, 2025		December 31, 2024
ROU assets	$	99	$	145

Lease liabilities:
Current lease liabilities	$	51	$	71
Long-term lease liabilities	48		74
Total lease liabilities, net	$	99	$	145

Schedule of Operating Lease Additional Information

Additional information for the Company’s operating leases is presented below:


	Years Ended December 31,
	2025		2024		2023
Lease cost:

Operating lease cost	$	91	$	88	$	107
Short-term lease cost	45		62		40
Total lease cost	$	136	$	150	$	147

Other information:
Operating cash outflows from operating leases	$	32	$	13	$	10
Investing cash outflows from operating leases	$	104	$	137	$	137


	December 31, 2025		December 31, 2024
Weighted average remaining lease term - operating leases	2.49 years		3.03 years
Weighted average discount rate - operating leases	5.77	%	5.99	%

Schedule of Maturity Analysis of Operating Lease Liabilities

Maturity analysis of operating lease liabilities is presented below:


	December 31, 2025
2026	$	51
2027	34
2028	15
2029	6
2030	—
Thereafter	1
Total lease payments	107
Less imputed interest	(8)
Present value of lease liabilities	99
Less current maturities	(51)
Present value of lease liabilities, less current maturities	$	48

Earnings Per Share - Reconciliation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Earnings Per Share [Abstract]
Net income (loss) available to common stockholders, basic	$ 1,819	$ (714)	$ 2,419
Net income (loss) available to common stockholders, diluted	$ 1,819	$ (714)	$ 2,419
Weighted average common shares outstanding, basic (in shares)	237,290	156,989	132,840
Effect of potentially dilutive securities
Warrants (in shares)	2,670	0	9,750
Restricted stock units (in shares)	372	0	338
Performance share units (in shares)	38	0	48
Weighted average common shares outstanding, diluted (in shares)	240,370	156,989	142,976
Earnings per common share:
Basic (in dollars per share)	$ 7.67	$ (4.55)	$ 18.21
Diluted (in dollars per share)	$ 7.57	$ (4.55)	$ 16.92

Segment Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Segment Information


18.			Segment Information

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the CODM, who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. Our revenues are derived from the production, marketing and sale of natural gas, oil and NGL. Additional information on our revenues, including the disaggregation of our revenues and major customers, is found in Note 8. As of December 31, 2025, we considered each of our operating areas as operating segments, however, we have aggregated those operating segments into one reportable segment due to the similar nature of the exploration and production business across Expand Energy and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations.

Our CODM uses consolidated net income (loss), for purposes of allocating resources and in assessing Expand Energy’s operating performance, which also includes analyzing results to forecasted information. Additionally, our CODM is regularly provided information on production expense, gathering, processing and transportation expense, severance and ad valorem taxes and general and administrative expense, which are our significant segment expenses. Other segment items primarily consist of depreciation, depletion and amortization, marketing expense, interest expense and income tax expense (benefit). Our significant segment expenses and other segment items are derived from, and can be found within the consolidated statements of operations.

The measure of segment assets is total assets as reported on our consolidated balance sheets, and as of December 31, 2025 and 2024 our total assets were $28,287 million and $27,894 million, respectively. Additionally, in analyzing company performance, our CODM reviews capital expenditures. During the years ended December 31, 2025, 2024 and 2023, our capital expenditures were $2,852 million, $1,529 million and $1,782 million, respectively. We did not make any contributions to equity method investments during the year ended December 31, 2025 and during the years ended December 31, 2024 and 2023, we contributed approximately $58 million and $220 million, respectively, to equity method investments, which primarily consisted of our investment with Momentum Sustainable Ventures LLC. Additional discussion around our investment with Momentum Sustainable Ventures LLC is in Note 15. Our interest revenue during the years ended December 31, 2025, 2024 and 2023 was $16 million, $45 million and $29 million, respectively.

- 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.

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-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

+ Details

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivatives, Fair Value [Line Items]
Short-term derivative asset	$ 264	$ 84
Long-term derivative asset	47	1
Short-term derivative liability	(3)	(71)
Long-term derivative liability	(1)	(68)
Not designated as hedging instrument
Derivatives, Fair Value [Line Items]
Derivative asset (liability), fair value, gross asset (liability)	307	(54)
Derivative asset (liability) fair value, net asset (liability), netted	0	0
Total derivatives	307	(54)
Not designated as hedging instrument \| Commodity contracts
Derivatives, Fair Value [Line Items]
Short-term derivative asset	264	84
Long-term derivative asset	47	1
Short-term derivative liability	(3)	(71)
Long-term derivative liability	(1)	(68)
Not designated as hedging instrument \| Commodity contracts \| Short-term derivative asset
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	340	191
Derivative asset, fair value, gross liability, netted	(76)	(107)
Not designated as hedging instrument \| Commodity contracts \| Long-term derivative asset
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, gross asset	66	6
Derivative asset, fair value, gross liability, netted	(19)	(5)
Not designated as hedging instrument \| Commodity contracts \| Short-term derivative liability
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(79)	(178)
Derivative liability, fair value, gross asset, netted	76	107
Not designated as hedging instrument \| Commodity contracts \| Long-term derivative liability
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, gross liability	(20)	(73)
Derivative liability, fair value, gross asset, netted	$ 19	$ 5

Natural Gas and Oil Property Transactions - Purchase Price Allocation (Details) - Southwestern $ in Millions	Oct. 01, 2024 USD ($)
Consideration:
Cash	$ 585
Fair value of Expand Energy common stock issued	7,871
Restricted stock unit and performance stock unit replacement awards	17
Total consideration	8,473
Fair Value of Assets Acquired:
Cash and cash equivalents and restricted cash	126
Other current assets	828
Proved natural gas and oil properties	10,002
Unproved properties	4,270
Other property and equipment	128
Other long-term assets	496
Amounts attributable to assets acquired	15,850
Fair Value of Liabilities Assumed:
Current liabilities	1,955
Long-term debt	3,305
Deferred tax liabilities	479
Long-term contract liabilities	1,287
Other long-term liabilities	351
Amounts attributable to liabilities assumed	7,377
Total identifiable net assets	8,473
2022 Southwestern's Revolving Credit Facility
Fair Value of Liabilities Assumed:
Repayment of revolving credit facility	585
Accrued interest and fees	$ 2

Derivative and Hedging Activities - Narrative (Details)	Dec. 31, 2025 USD ($) derivative counterparty	Dec. 31, 2024 derivative
Derivative [Line Items]
Posted collateral \| $	$ 0
Energy related derivative
Derivative [Line Items]
Number of counterparties in hedge facility \| counterparty	19
Designated as hedging instrument
Derivative [Line Items]
Number of derivative instruments \| derivative	0	0

- Definition

The number of derivative instruments of a particular group held by the entity.

+ References + Details

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

Revenue - Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Disaggregation of Revenue [Line Items]
Allowance for doubtful accounts	$ (14)	$ (11)
Total accounts receivable, net	1,599	1,226
Natural gas, oil and NGL sales
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	1,363	1,028
Joint interest
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	232	191
Other
Disaggregation of Revenue [Line Items]
Accounts receivable, gross	$ 18	$ 18

- 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 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-5

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
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-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 91
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479777/606-10-55-91

+ Details

Supplemental Cash Flow Information - Supplemental Disclosure (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Changes in assets and liabilities
Accounts receivable	$ (370)	$ (168)	$ 857
Accounts payable	(68)	(62)	(152)
Other current assets	(40)	3	143
Other current liabilities	193	(88)	(573)
Total	(285)	(315)	275
Supplemental cash flow information:
Interest paid, net of capitalized interest	230	93	117
Income taxes paid (refunds received), net
Federal	80	7	120
Income taxes paid (refunds received)	(14)	(10)	12
Income taxes paid (refunds received), net	66	(3)	132
Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs	114	(49)	(31)
Common stock issued for business combination	0	7,888	0
Operating lease obligations recognized	39	137	96
Liabilities established in connection with property acquisitions	$ 29	$ 0	$ 0

Investments (Details)	12 Months Ended
Investments (Details)	Dec. 31, 2025 USD ($) MMcf	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Schedule of Equity Method Investments [Line Items]
Gathering, processing and transportation	$ 2,376,000,000	$ 1,035,000,000	$ 853,000,000
Accounts payable	$ 753,000,000	777,000,000
Momentum Sustainable Ventures L L C Member
Schedule of Equity Method Investments [Line Items]
Investment, ownership percentage	35.00%
Equity method investments	$ 313,000,000	$ 307,000,000
Accumulated capitalized interest costs	$ 29,000,000
Lag period (in months)	3 months	3 months	3 months
Impairments on investment	$ 0
NG3 gathering per day \| MMcf	900
Period for pipeline course	12 years
Gathering, processing and transportation	$ 15,000,000
Accounts payable	$ 12,000,000

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Extractive Industries [Abstract]
Proved	$ 26,606	$ 23,093
Unproved	5,478	5,897
Total	32,084	28,990
Less accumulated depreciation, depletion and amortization	(8,126)	(5,235)
Net capitalized costs	$ 23,958	$ 23,755

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The reconciliations between basic and diluted earnings (loss) per share are as follows:


	Years Ended December 31,
	2025		2024		2023
Numerator
Net income (loss) available to common stockholders, basic and diluted	$	1,819	$	(714)	$	2,419

Denominator (in thousands)
Weighted average common shares outstanding, basic	237,290		156,989		132,840
Effect of potentially dilutive securities
Warrants	2,670		—		9,750
Restricted stock units	372		—		338
Performance share units	38		—		48
Weighted average common shares outstanding, diluted	240,370		156,989		142,976

Earnings per common share:
Basic	$	7.67	$	(4.55)	$	18.21
Diluted	$	7.57	$	(4.55)	$	16.92

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited)


Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited)

Net Capitalized Costs

Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows:


	December 31, 2025		December 31, 2024
Natural gas and oil properties:
Proved	$	26,606	$	23,093
Unproved	5,478		5,897
Total	32,084		28,990
Less accumulated depreciation, depletion and amortization	(8,126)		(5,235)
Net capitalized costs	$	23,958	$	23,755

Unproved properties as of December 31, 2025 and December 31, 2024 primarily consisted of leasehold acquired through our Southwestern Merger in 2024. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.

Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development

Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows:


	Years Ended December 31,
	2025		2024		2023
Acquisition of properties(a):
Proved properties	$	5	$	10,010	$	10
Unproved properties	409		4,393		52
Exploratory costs	45		17		15
Development costs	2,751		1,420		1,721
Costs incurred	$	3,210	$	15,840	$	1,798

___________________________________________

(a) Includes $10.0 billion and $4.3 billion of proved and unproved property acquisitions, respectively, related to the Southwestern Merger in 2024.

Results of Operations from Natural Gas, Oil and NGL Producing Activities

The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities for the periods presented. It does not include any derivative activity, interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations.


	Years Ended December 31,
	2025		2024		2023
Natural gas, oil and NGL sales	$	8,476	$	2,969	$	3,547
Production expenses	(635)		(316)		(356)
Gathering, processing and transportation expenses	(2,376)		(1,035)		(853)
Severance and ad valorem taxes	(193)		(97)		(167)
Exploration	(46)		(10)		(27)
Depletion and depreciation	(2,890)		(1,673)		(1,478)
Accretion of asset retirement obligations	(30)		(18)		(16)
Imputed income tax provision(a)	(542)		42		(152)
Results of operations from natural gas, oil and NGL producing activities	$	1,764	$	(138)	$	498

___________________________________________

(a) The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).

Natural Gas, Oil and NGL Reserve Quantities

Our petroleum engineers estimated all of our proved reserves as of December 31, 2025, 2024 and 2023. Independent petroleum engineering firm Netherland, Sewell & Associates, Inc. audited our total proved reserves as of December 31, 2025.

Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL 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 – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program

was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The information provided below on our natural gas, oil and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.

Presented below is a summary of changes in estimated proved reserves for the periods presented:


	Natural Gas	Oil	NGL	Total
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
December 31, 2025
Proved reserves, beginning of period	16,924	67.9	578.1	20,800
Extensions, discoveries and other additions	52	—	—	52
Revisions of previous estimates	8,008	(3.2)	(56.6)	7,650
Production	(2,409)	(5.9)	(29.6)	(2,622)
Sale of reserves-in-place	—	—	—	—
Purchase of reserves-in-place	—	—	—	—
Proved reserves, end of period	22,575	58.8	491.9	25,880
Proved developed reserves:
Beginning of period	14,418	40.3	383.0	16,958
End of period	16,395	35.0	328.5	18,576
Proved undeveloped reserves:
Beginning of period	2,506	27.6	195.1	3,842
End of period(a)	6,180	23.8	163.4	7,304

December 31, 2024
Proved reserves, beginning of period	9,688	—	—	9,688
Extensions, discoveries and other additions	124	—	—	124
Revisions of previous estimates	(1,654)	—	—	(1,654)
Production	(1,321)	(1.2)	(7.8)	(1,375)
Sale of reserves-in-place	—	—	—	—
Purchase of reserves-in-place	10,087	69.1	585.9	14,017
Proved reserves, end of period	16,924	67.9	578.1	20,800
Proved developed reserves:
Beginning of period	6,363	—	—	6,363
End of period	14,418	40.3	383.0	16,958
Proved undeveloped reserves:
Beginning of period	3,325	—	—	3,325
End of period(a)	2,506	27.6	195.1	3,842


	Natural Gas	Oil	NGL	Total
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)


December 31, 2023
Proved reserves, beginning of period	11,369	198.4	73.9	13,002
Extensions, discoveries and other additions	415	—	—	415
Revisions of previous estimates	(325)	—	—	(325)
Production	(1,266)	(7.7)	(3.8)	(1,335)
Sale of reserves-in-place	(563)	(190.7)	(70.1)	(2,127)
Purchase of reserves-in-place	58	—	—	58
Proved reserves, end of period	9,688	—	—	9,688
Proved developed reserves:
Beginning of period	7,385	157.2	58.9	8,681
End of period	6,363	—	—	6,363
Proved undeveloped reserves:
Beginning of period	3,984	41.2	15.0	4,321
End of period(a)	3,325	—	—	3,325

___________________________________________

(a) As of December 31, 2025, 2024 and 2023, there were no PUDs that had remained undeveloped for five years or more.

During 2025, we recorded 7,650 Bcfe of upward revisions of previous estimates, with 2,028 Bcfe of upward revisions due to higher natural gas prices in 2025 and 5,622 Bcfe due to non-price related positive revisions. The non-price positive revisions primarily consisted of 6,858 Bcfe of new PUDs and new producing wells that had improved economics and were in areas previously classified as proved, partially offset by 1,236 Bcfe of reserves decreases on existing proved properties. The non-price revision decreases were related to an update to the ethane recovery assumptions of 555 Bcfe as well as 146 Bcfe of negative non-price revisions related to updates to development plans, both of these revisions primarily within Southwest Appalachia. Additionally, 535 Bcfe of negative revisions were due to aligning production forecasts with latest production trends. We recorded extensions and discoveries of 52 Bcfe, primarily related to new PUDs in Southwest Appalachia. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2025, were $3.39 per Mcf, $65.34 per Bbl and $65.34 per Bbl, respectively, before basis differential adjustments.

During 2024, we acquired 14,017 Bcfe, primarily related to the Southwestern Merger. We recorded extensions and discoveries of 124 Bcfe, primarily related to new PUDs in Northeast Appalachia and previously unproved producing wells in both Northeast Appalachia and Haynesville. We recorded 1,654 Bcfe of downward revisions of previous estimates, with 2,395 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2024, partially offset by 741 Bcfe of non-price related positive revisions. The non-price revisions primarily consisted of 750 Bcfe of reserves increases on existing proved properties, related to increases in PUD forecasts and aligning forecasts for proved developed wells with latest production trends, increased ownership interests in some of the locations, and improved differentials in Haynesville. Also included within the non-price revisions were 174 Bcfe of new PUDs and producing wells in areas previously classified as proved, and 183 Bcfe of downward revisions due to development plan and other changes in Northeast Appalachia and Haynesville. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2024, were $2.13 per Mcf, $75.48 per Bbl and $75.48 per Bbl, respectively, before basis differential adjustments.

During 2023, we divested 2,127 Bcfe, primarily related to our Eagle Ford divestitures. We recorded extensions and discoveries of 415 Bcfe, primarily related to new PUDs and previously unproved producing wells in the Upper Marcellus and Bossier Shales. We recorded 325 Bcfe of downward revisions of previous estimates, with 1,623 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2023, partially offset by 1,298 Bcfe of non-price related positive revisions. The non-price revisions primarily consisted of 1,517 Bcfe from new PUDs and producing wells added in previously proved areas, 469 Bcfe of positive revisions to previously recorded PUD reserves primarily due to expected longer laterals in both Northeast Appalachia and Haynesville, partially offset by downward revisions of 451 Bcfe due to development plan and other changes in Northeast Appalachia and Haynesville, and a downward revision of 237 Bcfe on proved developed reserves related to aligning forecasts with latest production trends. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2023, were $2.64 per Mcf, $78.22 per Bbl and $28.61 per Bbl, respectively, before basis differential adjustments.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Expand Energy has followed these guidelines which are briefly discussed below.

Future cash inflows and future production and development costs as of December 31, 2025, 2024 and 2023 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure:


	Years Ended December 31,
	2025			2024			2023
Future cash inflows	$	54,193	(a)	$	24,213	(b)	$	14,659	(c)
Future production costs	(10,794)			(7,007)			(3,326)
Future development costs	(6,397)		(d)	(3,537)		(e)	(2,779)		(f)
Future income tax provisions	(4,603)			(119)			(174)
Future net cash flows	32,399			13,550			8,380
Less effect of a 10% discount factor	(15,273)			(6,019)			(3,903)
Standardized measure of discounted future net cash flows	$	17,126		$	7,531		$	4,477

___________________________________________

(a) Calculated using prices of $3.39 per Mcf of natural gas, $65.34 per Bbl of oil and $65.34 per Bbl of NGL, before basis differential adjustments.

(b) Calculated using prices of $2.13 per Mcf of natural gas, $75.48 per Bbl of oil and $75.48 per Bbl of NGL, before basis differential adjustments.

(d) Included approximately $2,120 million of future plugging and abandonment costs as of December 31, 2025.

(e) Included approximately $1,625 million of future plugging and abandonment costs as of December 31, 2024.

(f) Included approximately $730 million of future plugging and abandonment costs as of December 31, 2023.

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:


	Years Ended December 31,
	2025		2024		2023
Standardized measure, beginning of period	$	7,531	$	4,477	$	26,305
Sales of natural gas, oil and NGL produced, net of production costs and gathering, processing and transportation(a)	(5,272)		(1,521)		(2,171)
Net changes in prices and production costs	11,359		(2,266)		(23,535)
Extensions and discoveries, net of production and development costs	19		50		182
Changes in estimated future development costs	(2,316)		652		346
Previously estimated development costs incurred during the period	827		396		818
Revisions of previous quantity estimates	7,109		(922)		(205)
Purchase of reserves-in-place	—		5,409		77
Sales of reserves-in-place	—		—		(7,158)
Accretion of discount	757		457		3,270
Net change in income taxes	(2,213)		58		6,301
Changes in production rates and other	(675)		741		247
Standardized measure, end of period(a)	$	17,126	$	7,531	$	4,477

___________________________________________

(a) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.

- 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
-SubTopic 270
-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
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477759/932-235-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/932/tableOfContent

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 36
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-36

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-5

+ Details

Other Property and Equipment

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Other Property and Equipment


14.			Other Property and Equipment

A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:


					Estimated Useful Life
	December 31, 2025		December 31, 2024
					(in years)
Buildings and improvements	$	135	$	329	10 - 39
Computer equipment	110		110		5
Gathering and water systems	76		78		7 - 20
Machinery and equipment	53		40		7 - 10
Land	25		29
Other	110		68		3 - 15
Total other property and equipment, at cost	509		654
Less: accumulated depreciation	(152)		(127)
Total other property and equipment, net	$	357	$	527

On December 31, 2025, we sold a portion of our Oklahoma City campus and recognized a loss of $69 million based on the difference between the carrying value of the assets and the consideration received. Additionally, as of December 31, 2025, we signed agreements to sell other parts of our Oklahoma City campus. Approximately $40 million was classified as held for sale related to these agreements and we recognized asset impairments of $37 million based on the difference between the carrying value of the assets and the agreed upon sale price. We anticipate these agreements closing in the first quarter of 2026.

Other Property and Equipment - Schedule of Other Property and Equipment Held for Use and Estimated Useful Lives (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 509	$ 654
Less: accumulated depreciation	(152)	(127)
Total other property and equipment, net	357	527
Buildings and improvements
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 135	329
Buildings and improvements \| Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	10 years
Buildings and improvements \| Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	39 years
Computer equipment
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 110	110
Estimated Useful Life	5 years
Gathering and water systems
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 76	78
Gathering and water systems \| Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	7 years
Gathering and water systems \| Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	20 years
Machinery and equipment
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 53	40
Machinery and equipment \| Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	7 years
Machinery and equipment \| Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	10 years
Land
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 25	29
Other
Property, Plant and Equipment [Abstract]
Total other property and equipment, at cost	$ 110	$ 68
Other \| Minimum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	3 years
Other \| Maximum
Property, Plant and Equipment [Abstract]
Estimated Useful Life	15 years

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2025 Bcfe $ / Mcf	Dec. 31, 2024 Bcfe $ / Mcf	Dec. 31, 2023 Bcfe $ / Mcf $ / bbl	Dec. 31, 2025 $ / bbl	Dec. 31, 2025 $ / bbl	Dec. 31, 2024 $ / bbl	Dec. 31, 2024 $ / bbl
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	7,650	(1,654)	(325)
Extensions, discoveries and other additions	52	124	415
Purchase of reserves-in-place	0	14,017	58
Sale of reserves-in-place	0	0	2,127
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows \| $ / Mcf	3.39	2.13	2.64
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows			78.22	65.34	65.34	75.48	75.48
NGL
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Price used in computing estimated future cash inflows			28.61		65.34		75.48
Price Adjustment
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	2,028	(2,395)	(1,623)
Non-Price Related Revisions
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	5,622	741	1,298
Non-Price Revisions Reserves Increases
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	6,858	750
Non-Price Revisions Reserves Decreases
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(1,236)
Revisions Due to Update to the Ethane Recovery Assumptions
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(555)
Revisions Due to Development Plan Optimization
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(146)	(183)	(451)
Revisions Due to Performance
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates	(535)		(237)
New PUDs and Producing Wells Added in Previously Proved Areas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates		174	1,517
Revisions Due to Lateral Length Adjustments
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Revisions of previous estimates			469

Other Property and Equipment - Narrative (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 31, 2025	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Property and equipment held for sale, net	$ 40	$ 40	$ 0
Asset impairments		$ 37	$ 0	$ 0
Disposal group, disposed of by sale, not discontinued operations
Property, Plant and Equipment [Line Items]
Loss on sale of property and equipment	$ (69)

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations


16.			Asset Retirement Obligations

The components of the change in our asset retirement obligations are shown below:


	Years Ended December 31,
	2025		2024
Asset retirement obligations, beginning of period	$	531	$	276
Additions(a)	16		263
Revisions(b)	157		(21)
Settlements and disposals	(10)		(5)
Accretion expense	30		18
Asset retirement obligations, end of period	724		531
Less current portion	36		32
Asset retirement obligations, long-term	$	688	$	499

___________________________________________

(a) During the year ended December 31, 2024, approximately $251 million of additions relate to the Southwestern Merger. See Note 2 for further discussion of this transaction.

(b) In 2025, revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs.

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash flows from operating activities:
Net income (loss)	$ 1,819	$ (714)	$ 2,419
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	2,980	1,729	1,527
Deferred income tax expense (benefit)	448	(123)	428
Derivative (gains) losses, net	(550)	38	(1,728)
Cash receipts on derivative settlements, net	189	947	354
Share-based compensation	46	38	33
(Gains) losses on sales of assets	65	(14)	(946)
Contract amortization	(203)	(57)	0
(Gains) losses on purchases, exchanges or extinguishments of debt	(4)	1	0
Other	70	35	18
Changes in assets and liabilities	(285)	(315)	275
Net cash provided by operating activities	4,575	1,565	2,380
Cash flows from investing activities:
Capital expenditures	(2,736)	(1,557)	(1,829)
Property acquisitions	(195)	0	0
Receipts of deferred consideration	116	166	0
Business combination, net	0	(459)	0
Contributions to investments	(14)	(75)	(231)
Proceeds from divestitures of property and equipment	70	21	2,533
Net cash provided by (used in) investing activities	(2,759)	(1,904)	473
Cash flows from financing activities:
Proceeds from issuance of senior notes, net	0	747	0
Proceeds from warrant exercise	24	3	0
Debt issuance and other financing costs	(11)	(11)	0
Cash paid to repurchase and retire common stock	(100)	0	(355)
Cash paid to purchase debt	(663)	(767)	0
Cash paid for common stock dividends	(765)	(388)	(487)
Other	0	(3)	0
Net cash used in financing activities	(1,515)	(419)	(1,892)
Net increase (decrease) in cash, cash equivalents and restricted cash	301	(758)	961
Cash, cash equivalents and restricted cash, beginning of period	395	1,153	192
Cash, cash equivalents and restricted cash, end of period	696	395	1,153
Prior Credit Facility
Cash flows from financing activities:
Proceeds from Prior Credit Facility	825	20	1,125
Payments on Prior Credit Facility	(825)	(20)	(2,175)
2025 Credit Facility
Cash flows from financing activities:
Proceeds from Prior Credit Facility	165	0	0
Payments on Prior Credit Facility	$ (165)	$ 0	$ 0

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Balance at January 1	$ 80	$ 68	$ 69
Additions based on tax positions related to the current year	7	3	3
Additions to tax positions of prior years	1	1	3
Additions to tax positions related to acquisitions	0	9	0
Settlements	0	0	(5)
Reductions to tax positions of prior years	(24)	(1)	(2)
Balance at December 31	$ 64	$ 80	$ 68

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets:
Cash and cash equivalents	$ 616	$ 317
Restricted cash	80	78
Accounts receivable, net	1,599	1,226
Derivative assets	264	84
Other current assets	357	292
Total current assets	2,916	1,997
Natural gas and oil properties, successful efforts method
Proved natural gas and oil properties	26,606	23,093
Unproved properties	5,478	5,897
Other property and equipment	509	654
Total property and equipment	32,593	29,644
Less: accumulated depreciation, depletion and amortization	(8,278)	(5,362)
Property and equipment held for sale, net	40	0
Total property and equipment, net	24,355	24,282
Long-term derivative assets	47	1
Deferred income tax assets	168	589
Other long-term assets	801	1,025
Total assets	28,287	27,894
Current liabilities:
Accounts payable	753	777
Current maturities of long-term debt, net	0	389
Accrued interest	100	100
Derivative liabilities	3	71
Other current liabilities	2,045	1,786
Total current liabilities	2,901	3,123
Long-term debt, net	5,009	5,291
Long-term derivative liabilities	1	68
Asset retirement obligations, net of current portion	688	499
Long-term contract liabilities	975	1,227
Other long-term liabilities	135	121
Total liabilities	9,709	10,329
Contingencies and commitments (Note 5)
Stockholders' equity:
Common stock, $0.01 par value, 450,000,000 shares authorized: 239,249,874 and 231,769,886 shares issued	2	2
Additional paid-in capital	13,746	13,687
Retained earnings	4,830	3,876
Total stockholders' equity	18,578	17,565
Total liabilities and stockholders' equity	$ 28,287	$ 27,894

Share-Based Compensation

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation


11.			Share-Based Compensation

Our long-term incentive plan, as amended and adopted by our Board of Directors (the “LTIP”), provides for the grant of restricted stock units (“RSUs”), restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors and has a share reserve equal to 6,800,000 shares of common stock.

Restricted Stock Units. During the years ended December 31, 2025, 2024 and 2023, we granted RSUs to employees and non-employee directors under the LTIP, which will vest over a three-year to five-year period and one-year period, respectively. The fair value of RSUs is based on the closing sales price of our common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. A summary of the changes in unvested RSUs is presented below:


	Unvested Restricted Stock Units	Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested as of December 31, 2022	957	$	68.91
Granted	440	$	72.25
Vested	(329)	$	61.66
Forfeited	(128)	$	68.42
Unvested as of December 31, 2023	940	$	73.08
Granted (a)	962	$	83.09
Vested (a)	(925)	$	74.18
Forfeited	(20)	$	77.71
Unvested as of December 31, 2024	957	$	81.99
Granted	557	$	103.38
Vested	(520)	$	80.52
Forfeited	(37)	$	98.24
Unvested as of December 31, 2025	957	$	94.61

_________________________________________

The aggregate intrinsic value of RSUs that vested during the years ended December 31, 2025, 2024 and 2023 was approximately $58 million, $77 million and $25 million, respectively, based on the stock price at the time of vesting.

As of December 31, 2025, there was approximately $58 million of total unrecognized compensation expense related to unvested RSUs. The expense is expected to be recognized over a weighted average period of approximately 1.93 years.

Performance Share Units. During the years ended December 31, 2025, 2024 and 2023, we granted performance share units (“PSUs”) to senior management and certain employees under the LTIP, which will generally vest over a three-year period and will be settled in shares. The performance criteria include total shareholder return (“TSR”) and relative TSR (“rTSR”) and could result in a total payout between 0% - 200% of the target units. The fair value of the PSUs was measured on the grant date using a Monte Carlo simulation, and compensation expense is recognized ratably over the requisite service period because these awards depend on a combination of service and market criteria.

The following table presents the assumptions used in the valuation of the PSUs granted during the years ended December 31, 2025, 2024 and 2023.


Assumption - TSR, rTSR	2025 PSU Awards		2024 PSU Awards		2023 PSU Awards
Risk-free interest rate	4.00	%	4.55	%	3.85	%
Volatility	33.40	%	39.36	%	64.4	%

A summary of the changes in unvested PSUs is presented below:


	Unvested Performance Share Units	Weighted Average Grant Date Fair Value Per Share
	(in thousands)
Unvested as of December 31, 2022	276	$	88.28
Granted	131	$	78.78
Vested	—	$	—
Forfeited	(13)	$	68.77
Unvested as of December 31, 2023	394	$	85.78
Granted	133	$	95.33
Vested	(151)	$	71.29
Forfeited	—	$	—
Unvested as of December 31, 2024	376	$	94.67
Granted	250	$	125.64
Vested	(132)	$	108.56
Forfeited	(30)	$	113.86
Unvested as of December 31, 2025	464	$	106.14

The aggregate intrinsic value of PSUs that vested during the years ended December 31, 2025 and 2024 was approximately $22 million and $19 million, respectively, based on the stock price at the time of vesting.

As of December 31, 2025, there was approximately $26 million of total unrecognized compensation expense related to unvested PSUs. The expense is expected to be recognized over a weighted average period of approximately 2.03 years.

RSU and PSU Compensation.

We recognized the following compensation costs, net of actual forfeitures, related to RSUs and PSUs for the periods presented:


	Years Ended December 31,
	2025		2024		2023
General and administrative expenses	$	37	$	33	$	29
Natural gas and oil properties	8		7		6
Production expense	6		4		4
Separation and other termination costs	2		9		—
Marketing expense	3		—		—
Other operating expense, net	4		28		—
Total RSU and PSU compensation	$	60	$	81	$	39
Related income tax benefit	$	13	$	13	$	7

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Revenues and Expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Extractive Industries [Abstract]
Natural gas, oil and NGL sales	$ 8,476	$ 2,969	$ 3,547
Production expenses	(635)	(316)	(356)
Gathering, processing and transportation expenses	(2,376)	(1,035)	(853)
Severance and ad valorem taxes	(193)	(97)	(167)
Exploration	(46)	(10)	(27)
Depletion and depreciation	(2,890)	(1,673)	(1,478)
Accretion of asset retirement obligations	(30)	(18)	(16)
Imputed income tax provision	(542)	42	(152)
Results of operations from natural gas, oil and NGL producing activities	$ 1,764	$ (138)	$ 498

Leases

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Leases


7.			Leases

We are a lessee under various agreements for drilling rigs, pressure pumping equipment, vehicles, office space, compressors and other equipment under non-cancelable operating leases expiring through 2036. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The Company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the right of use (“ROU”) asset and lease liability balances. Regarding our drilling rigs and pressure pumping equipment, our policy is to treat both lease and non-lease components as a single lease component.

Our operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheets. Our total lease costs are recognized within proved natural gas and oil properties, production expenses and general and administrative expenses within our consolidated financial statements.

The following table presents our ROU assets and lease liabilities as of December 31, 2025 and 2024. As of December 31, 2025 and 2024, we did not have any finance leases.


	Operating Leases
	December 31, 2025		December 31, 2024
ROU assets	$	99	$	145

Lease liabilities:
Current lease liabilities	$	51	$	71
Long-term lease liabilities	48		74
Total lease liabilities, net	$	99	$	145

Additional information for the Company’s operating leases is presented below:


	Years Ended December 31,
	2025		2024		2023
Lease cost:

Operating lease cost	$	91	$	88	$	107
Short-term lease cost	45		62		40
Total lease cost	$	136	$	150	$	147

Other information:
Operating cash outflows from operating leases	$	32	$	13	$	10
Investing cash outflows from operating leases	$	104	$	137	$	137


	December 31, 2025		December 31, 2024
Weighted average remaining lease term - operating leases	2.49 years		3.03 years
Weighted average discount rate - operating leases	5.77	%	5.99	%

Maturity analysis of operating lease liabilities is presented below:


	December 31, 2025
2026	$	51
2027	34
2028	15
2029	6
2030	—
Thereafter	1
Total lease payments	107
Less imputed interest	(8)
Present value of lease liabilities	99
Less current maturities	(51)
Present value of lease liabilities, less current maturities	$	48

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Oklahoma City, Oklahoma
Auditor Firm ID	238

Equity - Schedule of Dividends (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Dividends Payable [Line Items]
Dividends													$ 765	$ 388	$ 487
O 2025 Q1 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)				$ 0.575
Dividends payable, variable (in dollars per share)				0
Rate Per Share (in dollars per share)				$ 0.575
Dividends				$ 138
O 2025 Q2 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)			$ 0.575
Dividends payable, variable (in dollars per share)			0
Rate Per Share (in dollars per share)			$ 0.575
Dividends			$ 138
O 2025 Q3 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)		$ 0.575
Dividends payable, variable (in dollars per share)		0.89
Rate Per Share (in dollars per share)		$ 1.465
Dividends		$ 351
O 2025 Q4 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)	$ 0.575
Dividends payable, variable (in dollars per share)	0
Rate Per Share (in dollars per share)	$ 0.575
Dividends	$ 138
O 2024 Q1 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)								$ 0.575
Dividends payable, variable (in dollars per share)								0
Rate Per Share (in dollars per share)								$ 0.575
Dividends								$ 77
O 2024 Q2 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)							$ 0.575
Dividends payable, variable (in dollars per share)							0.14
Rate Per Share (in dollars per share)							$ 0.715
Dividends							$ 95
O 2024 Q3 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)						$ 0.575
Dividends payable, variable (in dollars per share)						0
Rate Per Share (in dollars per share)						$ 0.575
Dividends						$ 78
O 2024 Q4 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)					$ 0.575
Dividends payable, variable (in dollars per share)					0
Rate Per Share (in dollars per share)					$ 0.575
Dividends					$ 134
O 2023 Q1 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)												$ 0.55
Dividends payable, variable (in dollars per share)												0.74
Rate Per Share (in dollars per share)												$ 1.29
Dividends												$ 175
O 2023 Q2 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)											$ 0.55
Dividends payable, variable (in dollars per share)											0.63
Rate Per Share (in dollars per share)											$ 1.18
Dividends											$ 160
O 2023 Q3 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)										$ 0.575
Dividends payable, variable (in dollars per share)										0
Rate Per Share (in dollars per share)										$ 0.575
Dividends										$ 77
O 2023 Q4 Dividends
Dividends Payable [Line Items]
Dividends payable, base (in dollars per share)									$ 0.575
Dividends payable, variable (in dollars per share)									0
Rate Per Share (in dollars per share)									$ 0.575
Dividends									$ 75

Natural Gas and Oil Property Transactions - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Revenues	$ 8,193	$ 14,247
Net income (loss) available to common stockholders	$ (607)	$ 3,852
Earnings (loss) per common share:
Basic (in dollars per share)	$ (2.65)	$ 16.86
Diluted (in dollars per share)	$ (2.65)	$ 16.14

Contingencies and Commitments (Details) - Gathering, Processing and Transportation Agreement $ in Millions	Dec. 31, 2025 USD ($)
Other Commitments [Line Items]
2026	$ 1,428
2027	1,337
2028	1,221
2029	1,019
2030	884
Thereafter	3,683
Total	$ 9,572

Share-Based Compensation - Compensation Expense (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 RSU and PSU compensation	$ 60	$ 81	$ 39
Related income tax benefit	13	13	7
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	37	33	29
Natural gas and oil properties
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	8	7	6
Production expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	6	4	4
Separation and other termination costs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	2	9	0
Marketing expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	3	0	0
Other operating expense, net
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total RSU and PSU compensation	$ 4	$ 28	$ 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 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (f)(2)
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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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 6: 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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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: 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 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

+ Details

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Schedule of Capitalized Costs

Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows:


	December 31, 2025		December 31, 2024
Natural gas and oil properties:
Proved	$	26,606	$	23,093
Unproved	5,478		5,897
Total	32,084		28,990
Less accumulated depreciation, depletion and amortization	(8,126)		(5,235)
Net capitalized costs	$	23,958	$	23,755

Schedule of Exploration Expense and Cost Incurred

Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows:


	Years Ended December 31,
	2025		2024		2023
Acquisition of properties(a):
Proved properties	$	5	$	10,010	$	10
Unproved properties	409		4,393		52
Exploratory costs	45		17		15
Development costs	2,751		1,420		1,721
Costs incurred	$	3,210	$	15,840	$	1,798

___________________________________________

(a) Includes $10.0 billion and $4.3 billion of proved and unproved property acquisitions, respectively, related to the Southwestern Merger in 2024.

Schedule of Revenues and Expenses


	Years Ended December 31,
	2025		2024		2023
Natural gas, oil and NGL sales	$	8,476	$	2,969	$	3,547
Production expenses	(635)		(316)		(356)
Gathering, processing and transportation expenses	(2,376)		(1,035)		(853)
Severance and ad valorem taxes	(193)		(97)		(167)
Exploration	(46)		(10)		(27)
Depletion and depreciation	(2,890)		(1,673)		(1,478)
Accretion of asset retirement obligations	(30)		(18)		(16)
Imputed income tax provision(a)	(542)		42		(152)
Results of operations from natural gas, oil and NGL producing activities	$	1,764	$	(138)	$	498

___________________________________________

Schedule of Changes in Estimated Reserves

Presented below is a summary of changes in estimated proved reserves for the periods presented:


	Natural Gas	Oil	NGL	Total
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
December 31, 2025
Proved reserves, beginning of period	16,924	67.9	578.1	20,800
Extensions, discoveries and other additions	52	—	—	52
Revisions of previous estimates	8,008	(3.2)	(56.6)	7,650
Production	(2,409)	(5.9)	(29.6)	(2,622)
Sale of reserves-in-place	—	—	—	—
Purchase of reserves-in-place	—	—	—	—
Proved reserves, end of period	22,575	58.8	491.9	25,880
Proved developed reserves:
Beginning of period	14,418	40.3	383.0	16,958
End of period	16,395	35.0	328.5	18,576
Proved undeveloped reserves:
Beginning of period	2,506	27.6	195.1	3,842
End of period(a)	6,180	23.8	163.4	7,304

December 31, 2024
Proved reserves, beginning of period	9,688	—	—	9,688
Extensions, discoveries and other additions	124	—	—	124
Revisions of previous estimates	(1,654)	—	—	(1,654)
Production	(1,321)	(1.2)	(7.8)	(1,375)
Sale of reserves-in-place	—	—	—	—
Purchase of reserves-in-place	10,087	69.1	585.9	14,017
Proved reserves, end of period	16,924	67.9	578.1	20,800
Proved developed reserves:
Beginning of period	6,363	—	—	6,363
End of period	14,418	40.3	383.0	16,958
Proved undeveloped reserves:
Beginning of period	3,325	—	—	3,325
End of period(a)	2,506	27.6	195.1	3,842


	Natural Gas	Oil	NGL	Total
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)


December 31, 2023
Proved reserves, beginning of period	11,369	198.4	73.9	13,002
Extensions, discoveries and other additions	415	—	—	415
Revisions of previous estimates	(325)	—	—	(325)
Production	(1,266)	(7.7)	(3.8)	(1,335)
Sale of reserves-in-place	(563)	(190.7)	(70.1)	(2,127)
Purchase of reserves-in-place	58	—	—	58
Proved reserves, end of period	9,688	—	—	9,688
Proved developed reserves:
Beginning of period	7,385	157.2	58.9	8,681
End of period	6,363	—	—	6,363
Proved undeveloped reserves:
Beginning of period	3,984	41.2	15.0	4,321
End of period(a)	3,325	—	—	3,325

___________________________________________

(a) As of December 31, 2025, 2024 and 2023, there were no PUDs that had remained undeveloped for five years or more.

Schedule of Future Net Cash Flows Relating to Proved Natural Gas, Oil and NGL Reserves Based on the Standardized Measure

The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure:


	Years Ended December 31,
	2025			2024			2023
Future cash inflows	$	54,193	(a)	$	24,213	(b)	$	14,659	(c)
Future production costs	(10,794)			(7,007)			(3,326)
Future development costs	(6,397)		(d)	(3,537)		(e)	(2,779)		(f)
Future income tax provisions	(4,603)			(119)			(174)
Future net cash flows	32,399			13,550			8,380
Less effect of a 10% discount factor	(15,273)			(6,019)			(3,903)
Standardized measure of discounted future net cash flows	$	17,126		$	7,531		$	4,477

___________________________________________

(a) Calculated using prices of $3.39 per Mcf of natural gas, $65.34 per Bbl of oil and $65.34 per Bbl of NGL, before basis differential adjustments.

(b) Calculated using prices of $2.13 per Mcf of natural gas, $75.48 per Bbl of oil and $75.48 per Bbl of NGL, before basis differential adjustments.

(d) Included approximately $2,120 million of future plugging and abandonment costs as of December 31, 2025.

(e) Included approximately $1,625 million of future plugging and abandonment costs as of December 31, 2024.

(f) Included approximately $730 million of future plugging and abandonment costs as of December 31, 2023.

Schedule of Sources of Change in Standardized Measure of Discounted Future Net Cash Flow

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:


	Years Ended December 31,
	2025		2024		2023
Standardized measure, beginning of period	$	7,531	$	4,477	$	26,305
Sales of natural gas, oil and NGL produced, net of production costs and gathering, processing and transportation(a)	(5,272)		(1,521)		(2,171)
Net changes in prices and production costs	11,359		(2,266)		(23,535)
Extensions and discoveries, net of production and development costs	19		50		182
Changes in estimated future development costs	(2,316)		652		346
Previously estimated development costs incurred during the period	827		396		818
Revisions of previous quantity estimates	7,109		(922)		(205)
Purchase of reserves-in-place	—		5,409		77
Sales of reserves-in-place	—		—		(7,158)
Accretion of discount	757		457		3,270
Net change in income taxes	(2,213)		58		6,301
Changes in production rates and other	(675)		741		247
Standardized measure, end of period(a)	$	17,126	$	7,531	$	4,477

___________________________________________

(a) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.

- 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

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Debt


4.			Debt

Our long-term debt consisted of the following as of December 31, 2025 and 2024:


	December 31, 2025				December 31, 2024
	Carrying Amount		Fair Value(a)		Carrying Amount		Fair Value(a)
2025 Credit Facility	$	—	$	—	$	—	$	—
Prior Credit Facility	—		—		—		—
4.95% senior notes due 2025(b)	—		—		389		389
5.50% senior notes due 2026	—		—		47		47
5.375% senior notes due 2029(b)	638		639		700		684
5.875% senior notes due 2029	440		441		500		494
6.75% senior notes due 2029	847		852		950		959
5.375% senior notes due 2030(b)	1,200		1,218		1,200		1,174
4.75% senior notes due 2032(b)	1,150		1,137		1,150		1,067
5.70% senior notes due 2035(c)	750		776		750		734
Premiums (discounts) on senior notes, net	(8)		—		4		—
Debt issuance costs	(8)		—		(10)		—
Total debt, net	5,009		5,063		5,680		5,548
Less current maturities of long-term debt, net	—		—		(389)		(389)
Total long-term debt, net	$	5,009	$	5,063	$	5,291	$	5,159

____________________________________________

(a)The carrying value of borrowings under our 2025 Credit Facility and Prior Credit Facility approximates fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value.

(b)On October 1, 2024, we assumed the debt of Southwestern in connection with the Southwestern Merger, which primarily consisted of these senior notes. See Note 2 for additional discussion on the Southwestern Merger and further discussion of these senior notes below.

(c)On December 2, 2024, we issued $750 million of 5.70% senior notes. See further discussion below.

The table below presents debt maturities as of December 31, 2025, excluding debt issuance costs, discounts and premiums:


	Total




2029	1,925
2030	1,200
Thereafter	1,900
Total debt	$	5,025

Credit Facility. On September 30, 2025, the Company entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) that, as amended, has a maturity date of September 30, 2030 (the “2025 Credit Facility”), with the lenders and issuing banks party thereto from time to time (the “Lenders”), and JPMorgan Chase Bank, N.A., as administrative agent. The 2025 Credit Facility, among other things, extended the maturity date from December 2027 to September 2030, with two one-year extension options available, each subject to the Lenders’ consent, increased the aggregate commitments under the 2025 Credit Facility from $2.5 billion to $3.5 billion with incremental capacity for additional commitments in an amount up to $1.0 billion, subject to the receipt of commitments thereto and certain customary conditions. The Credit Agreement also increased the sublimit available for the issuance of letters of credit from $500 million to $1.0 billion, and increased the sublimit available for swingline loans from $50 million to $100 million. As of December 31, 2025, we had approximately $3.5 billion available for borrowings under the 2025 Credit Facility.

The Credit Agreement contains restrictive covenants that, subject to exceptions customary to investment-grade credit facilities, limit Expand Energy and its subsidiaries’ ability to, among other things: (i) incur priority indebtedness, (ii) enter into mergers; (iii) make or declare dividends; (iv) incur liens; (v) sell all or substantially all of their assets; and (vi) engage in certain transactions with affiliates. The Credit Agreement requires our compliance with an indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity (the “Debt to Capitalization Ratio”), not to exceed 65%, tested at the end of each quarter. As of December 31, 2025, we were in compliance with the Debt to Capitalization Ratio.

Borrowings under the Credit Agreement may be alternate base rate loans or term SOFR loans, at our election. Interest is payable quarterly for alternate base rate loans and at the end of the applicable interest period for term SOFR loans. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 112.5 to 200 basis points per annum, depending on the Company’s unsecured debt ratings. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 12.5 to 100 basis points per annum, depending on the Company’s unsecured debt ratings. Expand Energy also pays a commitment fee on unused commitment amounts under the 2025 Credit Facility ranging from 12.5 to 32.5 basis points per annum, depending on the Company’s unsecured debt ratings.

The 2025 Credit Facility is subject to customary events of default, remedies, and cure periods for investment-grade credit facilities of this nature.

The Prior Credit Facility was terminated in connection with the entry into the 2025 Credit Facility.

Assumption of Southwestern’s Senior Notes and Southwestern Credit Facility Extinguishment.

On October 1, 2024, the Southwestern Merger was completed, and we became the successor issuer in respect to Southwestern’s (i) $389 million aggregate principal amount of 4.950% Senior Notes due 2025 (the “SWN 2025 Notes”), (ii) $304 million aggregate principal amount of 8.375% Senior Notes due 2028 (the “SWN 2028 Notes”), (iii) $700 million aggregate principal amount of 5.375% Senior Notes due 2029 (the “SWN 2029 Notes”), (iv) $1,200 million aggregate principal amount of 5.375% Senior Notes due 2030 (the “SWN 2030 Notes”) and (v) $1,150 million aggregate principal amount of 4.750% Senior Notes due 2032 (the “SWN 2032 Notes” and together with the SWN 2025 Notes, the SWN 2028 Notes, the SWN 2029 Notes and the SWN 2030 Notes, the “SWN Notes”). We assumed the obligations under (i) the SWN 2025 Notes pursuant to Supplemental Indenture No. 9 (“SWN 2025 Notes Supplemental Indenture No. 9”) to a base indenture dated January 23, 2015, by and among Southwestern and U.S. Bank National Association, as Trustee, (ii) the SWN 2028 Notes pursuant to Supplemental Indenture No. 9 (“SWN 2028 Notes Supplemental Indenture No. 9”) to a base indenture dated September 25, 2017, by and among Southwestern and U.S. Bank National Association, as Trustee, (iii) the SWN 2029 Notes pursuant to Supplemental Indenture No. 6 (“Supplemental Indenture No. 6”) to a base indenture dated August 30, 2021 (the “2021 Base Indenture”) by and among Southwestern and Regions Bank, as Trustee, (iv) the 2030 Notes pursuant to Supplemental Indenture No. 7 (“Supplemental Indenture No. 7”) to the 2021 Base Indenture and (v) the 2032 Notes pursuant to Supplemental Indenture No. 8 (“Supplemental Indenture No. 8” and, together with SWN 2025 Notes Supplemental Indenture No. 9, SWN 2028 Notes Supplemental Indenture No. 9, Supplemental Indenture No. 6 and Supplemental Indenture No. 7, the “SWN Supplemental Indentures”) to the 2021 Base Indenture. In addition, pursuant to each SWN Supplemental Indenture, existing subsidiaries of the Company that guarantee our notes provided guarantees of the SWN Notes. As a result of the investment grade ratings we received on October 1 and

October 2, 2024, and the satisfaction of certain other conditions, all guarantees previously provided in connection with the Company’s outstanding senior notes, including the SWN Notes, were released.

The SWN 2025 Notes matured on January 23, 2025 and bore interest at a rate of 4.950% per annum, with interest that was payable on January 23 and July 23 of each year. The SWN 2029 Notes mature on February 1, 2029 and bear interest at a rate of 5.375% per annum, with interest payable on February 1 and August 1 of each year. The SWN 2030 Notes mature on March 15, 2030 and bear interest at a rate of 5.375% per annum, with interest payable on March 15 and September 15 of each year. The SWN 2032 Notes mature on February 1, 2032 and bear interest at a rate of 4.750% per annum, with interest payable on February 1 and August 1 of each year.

On October 1, 2024, Southwestern’s existing credit facility was terminated, with all loan amounts and other obligations outstanding thereunder repaid in full and all commitments thereunder extinguished, for approximately $585 million, which included all outstanding borrowings, accrued interest and transaction fees.

Issuance of 5.70% Senior Notes

On December 2, 2024, we completed our underwritten public offering of $750 million aggregate principal amount of our 5.70% Senior Notes due 2035 (the “2035 Notes”). The 2035 Notes were issued pursuant to the Indenture (the “Base Indenture”), dated as of December 2, 2024, between the Company and Regions Bank (the “Trustee”), as trustee, as supplemented by the First Supplemental Indenture, dated as of December 2, 2024 (the “First Supplemental Indenture” and, together with the Base Indenture, the “Indenture”), between the Company and the Trustee, setting forth specific terms applicable to the 2035 Notes.

The 2035 Notes are the Company’s senior unsecured obligations and rank equally in right to payment of the holders of the Company’s other current and future unsecured senior debt, including debt under the Company’s revolving credit facility and the Company’s existing senior notes, and senior in right of payment to any future subordinated debt that the Company may incur. The 2035 Notes are not guaranteed by any of the Company’s subsidiaries and are therefore structurally subordinated to any indebtedness incurred by any of the Company’s subsidiaries.

The 2035 Notes mature on January 15, 2035 and interest on the 2035 Notes is payable semi-annually, on January 15 and July 15 of each year to holders of record on the immediately preceding January 1 and July 1.

Outstanding Senior Notes. On October 28, 2024, the Company satisfied the “Investment Grade Date” conditions set forth under the Prior Credit Facility (the “Investment Grade Date Event”) and, as a result, entered into supplemental indentures pursuant to which each subsidiary guarantor party thereto was released of all of its obligations under its guarantee of the Company’s obligations under the indenture, dated as of February 5, 2021, among the Issuer, the guarantor party thereto and Deutsche Bank Trust Company Americas, as trustee, that issued the $500 million aggregate principal amount of 5.50% Senior Notes due 2026 (“the 2026 Notes”) and the $500 million aggregate principal amount of 5.875% Senior Notes due 2029 (the “2029 Notes”). Additionally, as a result of receiving such investment grade rating, pursuant to the indenture governing the 2026 Notes and the 2029 Notes, certain restrictive covenants under such indentures are no longer in effect upon the Company.

Interest on the 2026 Notes and 2029 Notes is payable semi-annually, on February 1 and August 1 of each year to holders of record on the immediately preceding January 15 and July 15.

The Company and certain of its subsidiaries previously agreed to guarantee such obligations under the indenture dated April 7, 2021 with Wilmington Trust, National Association, as Trustee (the “Vine Indenture”) under which the Company assumed the obligations under Vine’s $950 million aggregate principal amount of 6.75% Senior Notes due 2029 (the “Vine Notes”). Additionally, certain subsidiaries of Vine entered into a supplemental indenture to the Company’s existing indenture, dated February 5, 2021, with Deutsche Bank Trust Company Americas as trustee (the “CHK Indenture”), pursuant to which such subsidiaries of Vine have agreed to guarantee obligations under the CHK Indenture. On October 28, 2024, in connection with the Investment Grade Date Event, the Company entered into a supplemental indenture to the CHK Indenture pursuant to which each subsidiary guarantor party thereto was released of all its obligations under its guarantee of the Company’s obligations under the CHK Indenture.

Interest on the Vine Notes is payable semi-annually, on April 15 and October 15 of each year to holders of record on the immediately preceding April 1 and October 1.

In connection with the completion of the Southwestern Merger, on October 1, 2024, the Company entered into (i) Supplemental Indenture No. 3 to the Indenture dated February 5, 2021, by and among Chesapeake Escrow LLC, as issuer, the guarantors signatory thereto and Deutsche Bank Trust Company, as Trustee governing the 2026 Notes and 2029 Notes and (ii) Supplemental Indenture No. 5 to the Indenture dated April 7, 2021, by and among Vine Energy Holdings LLC, the guarantors signatory thereto and Wilmington Trust, National Association, as Trustee governing the Company’s existing 6.75% Senior Notes due 2029 (the “Vine Notes” and together with the 2026 Notes and the 2029 Notes, the “Existing Notes”), in each case to add as guarantors of the Existing Notes, the subsidiaries of Southwestern that guarantee SWN Notes that are described above. As discussed above, on October 28, 2024, each Southwestern subsidiary guarantor was released of all its obligations under its guarantee of the Company’s obligations under each of the indentures governing the Existing Notes in connection with the Investment Grade Date Event.

The 2025 Credit Facility, the SWN Notes and the Existing Notes are the Company’s senior unsecured obligations. Accordingly, they rank (i) equal in right of payment to all existing and future senior unsecured indebtedness, (ii) effectively subordinate in right of payment to all existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness, (iii) structurally subordinate in right of payment to all existing and future indebtedness and other liabilities of any future subsidiaries that do not guarantee the 2025 Credit Facility, the SWN Notes and/or Existing Notes and any entity that is not a subsidiary that does not guarantee the 2025 Credit Facility, the SWN Notes and/or Existing Notes and (iv) senior in right of payment to all future subordinated indebtedness.

The Company had no secured debt as of December 31, 2025.

Tender Offer and Senior Notes Repayment

During the fourth quarter of 2024, we announced an offer to purchase for cash, any and all of our outstanding 2026 Notes, the “Tender Offer”. Upon expiration of the Tender Offer, approximately 91%, or $453 million, of the 2026 Notes were validly tendered and not validly withdrawn. In a separate transaction during the fourth quarter of 2024, we redeemed all of the $304 million aggregate principal of the SWN 2028 Notes for approximately $312 million, which included an $8 million premium to call the notes. We utilized the proceeds from the 2035 Notes to fund the Tender Offer for the 2026 Notes and the early redemption of the SWN 2028 Notes.

In January 2025, the $389 million aggregate principal of SWN 2025 Notes was repaid and terminated with cash on hand and borrowings on the Prior Credit Facility. The borrowings on the Prior Credit Facility were subsequently repaid during the year ended December 31, 2025. In March 2025, we redeemed the remaining $47 million aggregate principal of the 5.50% Senior Notes due 2026 with cash on hand. During the year ended December 31, 2025, we redeemed approximately $103 million of our 6.750% Senior Notes due 2029, approximately $60 million of our 5.875% Senior Notes due 2029 and approximately $62 million of our 5.375% Senior Notes due 2029 through open market repurchases using cash on hand.

- 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.

+ References

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+ Details

Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies


1.			Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

On October 1, 2024, Chesapeake Energy Corporation (“Chesapeake”) changed its name to Expand Energy Corporation ("Expand Energy," “we,” “our,” “us” or the "Company") in connection with the Southwestern Merger, further discussed in Note 2. Following the Southwestern Merger, Expand Energy is the largest natural gas producer in the U.S., based on net daily production, and is focused on responsibly developing an abundant supply of natural gas, oil and NGL to expand energy access for all. We have operations in Louisiana, Texas, Pennsylvania, West Virginia and Ohio, with all of our operations located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Expand Energy were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Expand Energy has a controlling financial interest. Intercompany accounts and balances have been eliminated. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified.

This Annual Report on Form 10-K (this “Form 10-K”) relates to our financial position as of December 31, 2025 and as of December 31, 2024, and our results of operations for the year ended December 31, 2025, the year ended December 31, 2024 and the year ended December 31, 2023. For the time periods covered by this Form 10-K, we did not have any changes or items impacting other comprehensive income.

Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of natural gas and oil properties, natural gas and oil reserves, derivatives, income taxes, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.

Consolidation

We consolidate entities in which we have a controlling financial interest and variable interest entities in which we are the primary beneficiary. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 15 for further discussion of our investments. Undivided interests in natural gas and oil properties are consolidated on a proportionate basis.

Segments

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker (“CODM”), who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have one reportable segment, due to the similar nature of the exploration and production business across Expand Energy and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations. See Note 18 for additional information.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents.

Restricted Cash

As of December 31, 2025, we had restricted cash of $80 million. Our restricted cash represents funds restricted for payment of certain royalties pending the outcome of competing ownership claims for certain minerals, as well as for payment of certain convenience class unsecured claims.

Accounts Receivable

Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. See Note 8 for additional information regarding our accounts receivable.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for our natural gas and oil properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred.

Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil are capitalized.

Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed gas and oil reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves.

Proceeds from the sales of individual natural gas and oil properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

When circumstances indicate that the carrying value of proved natural gas and oil properties may not be recoverable, we compare 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 our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental

assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy. Additionally, we evaluate the carrying value of our unproved properties and record impairment based on time or geologic factors. Factors such as drilling results, reservoir performance, seismic interpretation, lease expiration dates or future plans to develop acreage is utilized in our evaluation of unproved properties. When unproved properties are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations.

Other Property and Equipment

Other property and equipment consists primarily of buildings and improvements, computers and office equipment, gathering and water systems, land and other assets that support our operations. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. See Note 14 for further discussion of other property and equipment.

Assets Held for Sale

We may market certain non-core natural gas and oil assets or other properties for sale. At the end of each reporting period, we evaluate if these assets should be classified as held for sale. The held for sale criteria includes the following: management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the criteria are met, then the assets and associated liabilities are classified as held for sale. Additionally, once assets are classified as held for sale, we cease depreciation on those related assets. See Note 14 for further discussion of other property and equipment.

Capitalized Interest

Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Accounts Payable

Included in accounts payable as of December 31, 2025 are liabilities of approximately $58 million, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance Costs

Costs associated with the arrangement of our credit facility are included in other long-term assets and are amortized over the life of the facility using the straight-line method. As of December 31, 2025, these costs were $22 million. Costs associated with the issuance of the senior notes are included in long-term debt and the remaining unamortized issuance costs are amortized over the life of the senior notes using the straight-line method. Unamortized issuance costs associated with our senior notes as of December 31, 2025 totaled $8 million.

Litigation Contingencies

We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 5 for further discussion of litigation contingencies.

Environmental Remediation Costs

We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. See Note 5 for discussion of environmental contingencies.

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 16 for further discussion of asset retirement obligations.

Revenue Recognition

Revenue from the sale of natural gas, oil and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property.

Revenue from contracts with customers includes the sale of our natural gas, oil and NGL production (recorded as natural gas, oil and NGL revenues in the consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the consolidated statements of operations). In connection with the marketing of these products, we obtain control of the natural gas, oil and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. See Note 8 for a presentation of the disaggregation of revenue.

Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers.

Generally our commodity sales contracts are less than 12 months in duration, however in certain cases we have long-term commodity sales contracts based on market prices at the time of delivery. With these long-term contracts, the transaction price is variable and determined as physical delivery occurs. As such, we have applied the practical expedient allowed in ASC 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied as of the end of the reporting period.

We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of natural gas, oil and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the consolidated statements of operations). In circumstances where we act as an agent rather than a principal, our results of operations related to natural gas, oil and NGL marketing activities are presented on a net basis.

Fair Value Measurements

Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and 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).

The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. See Notes 4 and 13 for further discussion of fair value measurements.

Derivatives

Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2025, none of our open derivative instruments were designated as cash flow hedges.

Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next 12 months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statements of cash flows. All of our commodity derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 13 for further discussion of our derivative instruments.

Income Taxes

We are subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and account for current income taxes based on amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded. Additionally, we account for deferred income taxes using the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.

We are required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. We recognize accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the consolidated statements of operations. See Note 9 for further discussion of income taxes.

Share-Based Compensation

Our share-based compensation program consists of restricted stock units and performance share units granted to employees and restricted stock units granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of services received in exchange for restricted stock units based on the fair value of the equity instruments as of the grant date. This value is amortized over the vesting period, which is generally three years from the grant date. Forfeitures on our share-based compensation awards are recognized as they occur. Because performance share units are settled in shares, they are classified as equity and are measured at fair value as of the grant date.

To the extent compensation expense relates to employees directly involved in the acquisition of natural gas and oil leasehold and development activities, these amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are generally recognized as general and administrative expense, production expense, marketing expense, or exploration expense, based on the employees involved in those activities. See Note 11 for further discussion of share-based compensation.

Recently Issued Accounting Standards

In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements. ASU 2025-11 clarifies interim disclosure requirements and the applicability of Topic 270. Additionally, ASU 2025-11 includes a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. This ASU is effective for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the impact this ASU will have on our disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. ASU 2024-03 expands disclosures about specific costs and expenses presented on the face of the income statement. This ASU is effective for annual reporting periods beginning after December 15, 2026 and for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the impact this ASU will have on our disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 intends to provide investors with additional information about an entity’s income taxes by requiring disclosure of items such as disaggregation of the effective tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective beginning with this annual report on Form 10-K and we have applied the updates retrospectively to impacted disclosures. See Note 9 for further discussion on our income taxes and Note 17 for additional information on income taxes paid.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments Disclosures. Under ASU 2023-07, the scope and frequency of segment disclosures is increased to provide investors with additional detail about information utilized by an entity’s CODM, including information about significant segment expenses. This ASU was effective for annual reporting beginning with our 2024 Form 10-K and for interim periods beginning with our quarterly report on Form 10-Q for the first quarter of 2025. See Note 18 for further discussion on our segment reporting.

We consider the applicability and impact of all ASUs. ASUs not listed above were evaluated and determined to either be not applicable, already adopted and disclosed or not material upon adoption.

Share-Based Compensation - Performance Share (Details) - Performance shares - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Unvested Performance Share Units
Unvested restricted stock, beginning balance (in shares)	376	394	276
Granted (in shares)	250	133	131
Vested (in shares)	(132)	(151)	0
Forfeited (in shares)	(30)	0	(13)
Unvested restricted stock, ending balance (in shares)	464	376	394
Weighted Average Grant Date Fair Value Per Share
Unvested restricted stock, beginning balance (in usd per share)	$ 94.67	$ 85.78	$ 88.28
Granted (in usd per share)	125.64	95.33	78.78
Vested (in usd per share)	108.56	71.29	0
Forfeited (in usd per share)	113.86	0	68.77
Unvested restricted stock, ending balance (in usd per share)	$ 106.14	$ 94.67	$ 85.78

Derivative and Hedging Activities

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative and Hedging Activities


13.			Derivative and Hedging Activities

We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our natural gas, oil and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open natural gas, oil and NGL derivative instruments were designated for hedge accounting as of December 31, 2025 and 2024.

Natural Gas, Oil and NGL Derivatives

As of December 31, 2025 and 2024, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:

•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and swap options.

•Options: We have bought and sold call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options and receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

•Collars: These instruments contain a fixed floor price (put) and ceiling price (call). In two-way collars, if the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. Additionally, if the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.

•Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.

The estimated fair values of our natural gas, oil and NGL derivative instrument assets (liabilities) as of December 31, 2025 and 2024 are provided below:


	December 31, 2025			December 31, 2024
	Notional Volume	Fair Value		Notional Volume	Fair Value
Natural gas (Bcf):
Fixed-price swaps	756	$	128	369	$	(28)
Two-way collars	1,143	212		1,098	(27)
Three-way collars	175	32		161	60
Call options (purchased)	—	—		73	1
Call options (sold)	73	(1)		219	(16)
Basis protection swaps	337	(66)		279	(39)
Total natural gas	2,484	305		2,199	(49)
Oil (MMBbls):
Three-way collars	—	$	2	2	$	4
Total oil	—	2		2	4
NGLs (MMBbls):
Fixed-price swaps	—	$	—	7	$	(9)
Total NGL	—	—		7	(9)


Total estimated fair value		$	307		$	(54)

Effect of Derivative Instruments – Consolidated Balance Sheets


	Gross Fair Value(a)		Amounts Netted in the Consolidated Balance Sheets		Net Fair Value Presented in the Consolidated Balance Sheets
As of December 31, 2025
Commodity Contracts:
Short-term derivative asset	$	340	$	(76)	$	264
Long-term derivative asset	66		(19)		47
Short-term derivative liability	(79)		76		(3)
Long-term derivative liability	(20)		19		(1)


Total derivatives	$	307	$	—	$	307

As of December 31, 2024
Commodity Contracts:
Short-term derivative asset	$	191	$	(107)	$	84
Long-term derivative asset	6		(5)		1
Short-term derivative liability	(178)		107		(71)
Long-term derivative liability	(73)		5		(68)


Total derivatives	$	(54)	$	—	$	(54)

___________________________________________

(a)These financial assets (liabilities) are measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below.

Fair Value

The fair value of our commodity derivatives is based on third-party pricing models, which utilize inputs that are either readily available in the public market, such as natural gas, oil and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes, and, as such, are classified as Level 2. These values are compared to the values given by our counterparties for reasonableness. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.

Credit Risk Considerations

Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we only enter into commodity contracts derivatives with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2025, our commodity contracts derivative instruments were spread among 19 counterparties.

Hedging Arrangements

Certain of our hedging arrangements are with counterparties that are also Lenders (or affiliates of Lenders) under our 2025 Credit Facility. We do not expect to post cash or letters of credit to secure our obligations under these hedging arrangements while we have our investment grade ratings. The obligations under these contracts must be secured by cash or letters of credit to the extent that any mark-to-market amounts exceed defined thresholds. As of December 31, 2025, we did not have any cash or letters of credit posted as collateral for our commodity derivatives.

- 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

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The components of the change in our asset retirement obligations are shown below:


	Years Ended December 31,
	2025		2024
Asset retirement obligations, beginning of period	$	531	$	276
Additions(a)	16		263
Revisions(b)	157		(21)
Settlements and disposals	(10)		(5)
Accretion expense	30		18
Asset retirement obligations, end of period	724		531
Less current portion	36		32
Asset retirement obligations, long-term	$	688	$	499

___________________________________________

(a) During the year ended December 31, 2024, approximately $251 million of additions relate to the Southwestern Merger. See Note 2 for further discussion of this transaction.

(b) In 2025, revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs.

Basis of Presentation and Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2025 USD ($) segment	Dec. 31, 2024 USD ($)
Summary of Significant Accounting Policies [Table] [Line Items]
Number of reportable segments \| segment	1
Restricted cash	$ 80,000,000	$ 78,000,000
Other accounts payable	58,000,000
Debt issuance costs	$ 8,000,000	$ 10,000,000
Revenue, payment terms	Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days.
Open derivative instruments designated as cash flow hedges	$ 0
Employee
Summary of Significant Accounting Policies [Table] [Line Items]
Vesting period	3 years
Credit facility
Summary of Significant Accounting Policies [Table] [Line Items]
Debt issuance costs	$ 22,000,000

Equity - Schedule of Warrants (Details) - shares	12 Months Ended
Equity - Schedule of Warrants (Details) - shares	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Warrant
Warrants and Rights Outstanding [Roll Forward]
Conversion of stock, shares issued (in shares)	7,497,509	4,083,103	221,952
Class A Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	1,254,479	4,247,615	4,495,004
Converted into common stock (in shares)	(1,238,774)	(2,993,136)	(247,389)
Issued for General Unsecured Claims (in shares)	0	0	0
Outstanding, ending balance (in shares)	15,705	1,254,479	4,247,615
Class B Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	3,073,194	4,403,064	4,404,564
Converted into common stock (in shares)	(3,024,393)	(1,329,870)	(1,500)
Issued for General Unsecured Claims (in shares)	0	0	0
Outstanding, ending balance (in shares)	48,801	3,073,194	4,403,064
Class C Warrants
Warrants and Rights Outstanding [Roll Forward]
Outstanding, beginning balance (in shares)	4,383,634	4,023,483	4,006,229
Converted into common stock (in shares)	(3,696,720)	(524,242)	(5,581)
Issued for General Unsecured Claims (in shares)	557,094	884,393	22,835
Outstanding, ending balance (in shares)	1,244,008	4,383,634	4,023,483
Warrants reserved for future issuance (in shares)	25,015

Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) - Schedule of Future Net Cash Flows Relating to Proved Reserves Based on Standardized Measure (Details) $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2025 $ / Mcf	Dec. 31, 2025 $ / bbl	Dec. 31, 2025 $ / bbl	Dec. 31, 2024 USD ($)	Dec. 31, 2024 $ / Mcf	Dec. 31, 2024 $ / bbl	Dec. 31, 2024 $ / bbl	Dec. 31, 2023 USD ($) $ / Mcf $ / bbl	Dec. 31, 2022 USD ($)
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future cash inflows	$ 54,193				$ 24,213				$ 14,659
Future production costs	(10,794)				(7,007)				(3,326)
Future development costs	(6,397)				(3,537)				(2,779)
Future income tax provisions	(4,603)				(119)				(174)
Future net cash flows	32,399				13,550				8,380
Less effect of a 10% discount factor	(15,273)				(6,019)				(3,903)
Standardized measure of discounted future net cash flows	17,126				7,531				4,477	$ 26,305
Future Development Costs
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Future plugging and abandonment costs	$ 2,120				$ 1,625				$ 730
Natural Gas
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Price used in computing estimated future cash inflows \| $ / Mcf		3.39				2.13			2.64
Oil
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Price used in computing estimated future cash inflows			65.34	65.34			75.48	75.48	78.22
NGL
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Line Items]
Price used in computing estimated future cash inflows				65.34				75.48	28.61

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Cash Flows [Abstract]
Cash and cash equivalents	$ 616	$ 317	$ 1,079
Restricted cash	80	78	74
Total cash, cash equivalents and restricted cash	$ 696	$ 395	$ 1,153

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements of Expand Energy were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Expand Energy has a controlling financial interest. Intercompany accounts and balances have been eliminated. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. This Annual Report on Form 10-K (this “Form 10-K”) relates to our financial position as of December 31, 2025 and as of December 31, 2024, and our results of operations for the year ended December 31, 2025, the year ended December 31, 2024 and the year ended December 31, 2023. For the time periods covered by this Form 10-K, we did not have any changes or items impacting other comprehensive income.
Accounting Estimates	Accounting Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of natural gas and oil properties, natural gas and oil reserves, derivatives, income taxes, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.
Consolidation	Consolidation We consolidate entities in which we have a controlling financial interest and variable interest entities in which we are the primary beneficiary. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 15 for further discussion of our investments. Undivided interests in natural gas and oil properties are consolidated on a proportionate basis.
Segments	Segments Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker (“CODM”), who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have one reportable segment, due to the similar nature of the exploration and production business across Expand Energy and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations.
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents.
Restricted Cash	Restricted Cash As of December 31, 2025, we had restricted cash of $80 million. Our restricted cash represents funds restricted for payment of certain royalties pending the outcome of competing ownership claims for certain minerals, as well as for payment of certain convenience class unsecured claims.
Accounts Receivable	Accounts Receivable Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible.
Natural Gas and Oil Properties	Natural Gas and Oil Properties We follow the successful efforts method of accounting for our natural gas and oil properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred. Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil are capitalized. Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed gas and oil reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves. Proceeds from the sales of individual natural gas and oil properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. When circumstances indicate that the carrying value of proved natural gas and oil properties may not be recoverable, we compare 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 our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy. Additionally, we evaluate the carrying value of our unproved properties and record impairment based on time or geologic factors. Factors such as drilling results, reservoir performance, seismic interpretation, lease expiration dates or future plans to develop acreage is utilized in our evaluation of unproved properties. When unproved properties are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations.
Other Property and Equipment	Other Property and Equipment Other property and equipment consists primarily of buildings and improvements, computers and office equipment, gathering and water systems, land and other assets that support our operations. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow.
Assets Held for Sale	Assets Held for Sale We may market certain non-core natural gas and oil assets or other properties for sale. At the end of each reporting period, we evaluate if these assets should be classified as held for sale. The held for sale criteria includes the following: management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the criteria are met, then the assets and associated liabilities are classified as held for sale. Additionally, once assets are classified as held for sale, we cease depreciation on those related assets.
Capitalized Interest	Capitalized Interest Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Accounts Payable	Accounts Payable Included in accounts payable as of December 31, 2025 are liabilities of approximately $58 million, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.
Debt Issuance Costs	Debt Issuance Costs Costs associated with the arrangement of our credit facility are included in other long-term assets and are amortized over the life of the facility using the straight-line method. As of December 31, 2025, these costs were $22 million. Costs associated with the issuance of the senior notes are included in long-term debt and the remaining unamortized issuance costs are amortized over the life of the senior notes using the straight-line method. Unamortized issuance costs associated with our senior notes as of December 31, 2025 totaled $8 million.
Litigation Contingencies	Litigation Contingencies We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred.
Environmental Remediation Costs	Environmental Remediation Costs We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Asset Retirement Obligations	Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties.
Revenue Recognition	Revenue Recognition Revenue from the sale of natural gas, oil and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. Revenue from contracts with customers includes the sale of our natural gas, oil and NGL production (recorded as natural gas, oil and NGL revenues in the consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the consolidated statements of operations). In connection with the marketing of these products, we obtain control of the natural gas, oil and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers. Generally our commodity sales contracts are less than 12 months in duration, however in certain cases we have long-term commodity sales contracts based on market prices at the time of delivery. With these long-term contracts, the transaction price is variable and determined as physical delivery occurs. As such, we have applied the practical expedient allowed in ASC 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied as of the end of the reporting period. We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of natural gas, oil and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the consolidated statements of operations). In circumstances where we act as an agent rather than a principal, our results of operations related to natural gas, oil and NGL marketing activities are presented on a net basis.
Fair Value Measurements	Fair Value Measurements Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and 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). The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.
Derivatives	Derivatives Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2025, none of our open derivative instruments were designated as cash flow hedges. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next 12 months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statements of cash flows. All of our commodity derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets. We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives.
Income Taxes	Income Taxes We are subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and account for current income taxes based on amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded. Additionally, we account for deferred income taxes using the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. We are required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. We recognize accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the consolidated statements of operations.
Share-Based Compensation	Share-Based Compensation Our share-based compensation program consists of restricted stock units and performance share units granted to employees and restricted stock units granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of services received in exchange for restricted stock units based on the fair value of the equity instruments as of the grant date. This value is amortized over the vesting period, which is generally three years from the grant date. Forfeitures on our share-based compensation awards are recognized as they occur. Because performance share units are settled in shares, they are classified as equity and are measured at fair value as of the grant date. To the extent compensation expense relates to employees directly involved in the acquisition of natural gas and oil leasehold and development activities, these amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are generally recognized as general and administrative expense, production expense, marketing expense, or exploration expense, based on the employees involved in those activities.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements. ASU 2025-11 clarifies interim disclosure requirements and the applicability of Topic 270. Additionally, ASU 2025-11 includes a disclosure principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. This ASU is effective for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the impact this ASU will have on our disclosures. In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. ASU 2024-03 expands disclosures about specific costs and expenses presented on the face of the income statement. This ASU is effective for annual reporting periods beginning after December 15, 2026 and for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the impact this ASU will have on our disclosures. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 intends to provide investors with additional information about an entity’s income taxes by requiring disclosure of items such as disaggregation of the effective tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective beginning with this annual report on Form 10-K and we have applied the updates retrospectively to impacted disclosures. See Note 9 for further discussion on our income taxes and Note 17 for additional information on income taxes paid. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments Disclosures. Under ASU 2023-07, the scope and frequency of segment disclosures is increased to provide investors with additional detail about information utilized by an entity’s CODM, including information about significant segment expenses. This ASU was effective for annual reporting beginning with our 2024 Form 10-K and for interim periods beginning with our quarterly report on Form 10-Q for the first quarter of 2025. See Note 18 for further discussion on our segment reporting. We consider the applicability and impact of all ASUs. ASUs not listed above were evaluated and determined to either be not applicable, already adopted and disclosed or not material upon adoption.

Revenue - Disaggregated Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Total
Disaggregation of Revenue [Line Items]
Revenues	$ 8,476	$ 2,969	$ 3,547
Total \| Haynesville
Disaggregation of Revenue [Line Items]
Revenues	3,477	1,205	1,300
Total \| Northeast Appalachia
Disaggregation of Revenue [Line Items]
Revenues	2,860	1,242	1,483
Total \| Southwest Appalachia
Disaggregation of Revenue [Line Items]
Revenues	2,139	522
Total \| Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues			764
Natural Gas
Disaggregation of Revenue [Line Items]
Revenues	7,433	2,686	2,853
Natural Gas \| Haynesville
Disaggregation of Revenue [Line Items]
Revenues	3,477	1,205	1,300
Natural Gas \| Northeast Appalachia
Disaggregation of Revenue [Line Items]
Revenues	2,860	1,242	1,483
Natural Gas \| Southwest Appalachia
Disaggregation of Revenue [Line Items]
Revenues	1,096	239
Natural Gas \| Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues			70
Oil
Disaggregation of Revenue [Line Items]
Revenues	319	69	596
Oil \| Haynesville
Disaggregation of Revenue [Line Items]
Revenues	0	0	0
Oil \| Northeast Appalachia
Disaggregation of Revenue [Line Items]
Revenues	0	0	0
Oil \| Southwest Appalachia
Disaggregation of Revenue [Line Items]
Revenues	319	69
Oil \| Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues			596
NGL
Disaggregation of Revenue [Line Items]
Revenues	724	214	98
NGL \| Haynesville
Disaggregation of Revenue [Line Items]
Revenues	0	0	0
NGL \| Northeast Appalachia
Disaggregation of Revenue [Line Items]
Revenues	0	0	0
NGL \| Southwest Appalachia
Disaggregation of Revenue [Line Items]
Revenues	724	214
NGL \| Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues			98
Marketing
Disaggregation of Revenue [Line Items]
Revenues	3,163	1,290	2,500
Natural Gas
Disaggregation of Revenue [Line Items]
Revenues	2,889	1,095	989
Oil
Disaggregation of Revenue [Line Items]
Revenues	132	116	1,332
NGL
Disaggregation of Revenue [Line Items]
Revenues	$ 142	$ 79	$ 179

Leases - ROU Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Assets and Liabilities, Lessee [Abstract]
ROU assets	$ 99	$ 145
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other long-term assets	Other long-term assets
Lease liabilities:
Current lease liabilities	$ 51	$ 71
Long-term lease liabilities	48	74
Operating Lease, Liability, Total	$ 99	$ 145
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Operating Lease, Liability, Statement of Financial Position [Extensible List]	Other Liabilities	Other Liabilities

Employee Benefit Plans

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Employee Benefit Plans


12.			Employee Benefit Plans

Our qualified 401(k) profit sharing plan (“401(k) Plan”) is the Expand Energy Corporation 401(k) Plan, which is open to employees of Expand Energy and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 6% of an employee's base salary and performance bonus) in cash. In addition to our employer match contributions, we have a discretionary fixed dollar contribution benefit for all employees, paid quarterly, which is based upon a calculation of 1% of Adjusted Free Cash Flow less the base quarterly dividend. This discretionary fixed dollar contribution is subject to an annual maximum contribution of $15,000 per employee. We contributed $25 million, $8 million and $13 million to the 401(k) Plan during the years ended December 31, 2025, 2024 and 2023, respectively.

- Definition

The entire disclosure for retirement benefits.

+ References

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

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

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

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480266/715-60-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/715/tableOfContent

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

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Other Liabilities Disclosure [Abstract]
Revenues and royalties due to others	$ 972	$ 734
Accrued drilling and production costs	350	296
Accrued compensation and benefits	107	124
Taxes payable	157	142
Operating leases	51	71
Joint interest prepayments received	11	13
Contract liabilities	253	284
Other	144	122
Total other current liabilities	$ 2,045	$ 1,786

Revenue (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following tables show revenue disaggregated by operating area and product type, for the periods presented:


	Year Ended December 31, 2025
	Natural Gas		Oil		NGL		Total
Haynesville	$	3,477	$	—	$	—	$	3,477
Northeast Appalachia	2,860		—		—		2,860
Southwest Appalachia	1,096		319		724		2,139
Natural gas, oil and NGL revenue	$	7,433	$	319	$	724	$	8,476

Marketing revenue	$	2,889	$	132	$	142	$	3,163


	Year Ended December 31, 2024
	Natural Gas		Oil		NGL		Total
Haynesville	$	1,205	$	—	$	—	$	1,205
Northeast Appalachia	1,242		—		—		1,242
Southwest Appalachia	239		69		214		522

Natural gas, oil and NGL revenue	$	2,686	$	69	$	214	$	2,969

Marketing revenue	$	1,095	$	116	$	79	$	1,290


	Year Ended December 31, 2023
	Natural Gas		Oil		NGL		Total
Haynesville	$	1,300	$	—	$	—	$	1,300
Northeast Appalachia	1,483		—		—		1,483

Eagle Ford	70		596		98		764

Natural gas, oil and NGL revenue	$	2,853	$	596	$	98	$	3,547

Marketing revenue	$	989	$	1,332	$	179	$	2,500

Schedule of Accounts Receivable

Accounts receivable as of December 31, 2025 and 2024 are detailed below:


	December 31, 2025		December 31, 2024
Natural gas, oil and NGL sales	$	1,363	$	1,028
Joint interest	232		191
Other	18		18
Allowance for doubtful accounts	(14)		(11)
Total accounts receivable, net	$	1,599	$	1,226

Revenue - Narrative (Details) - Revenue - Customer	12 Months Ended
Revenue - Narrative (Details) - Revenue - Customer	Dec. 31, 2025	Dec. 31, 2023
Customer A
Concentration Risk [Line Items]
Concentration risk, percentage	11.00%	17.00%
Customer B
Concentration Risk [Line Items]
Concentration risk, percentage		10.00%

- 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/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482861/275-10-50-20

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
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-Name Accounting Standards Codification
-Section 50
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-Subparagraph (d)
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-URI https://asc.fasb.org/1943274/2147482861/275-10-50-18

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 275
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (c)
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Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
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-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (b)
-Publisher FASB
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Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 275
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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
-Topic 954
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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478785/954-310-50-2

+ Details

- 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 - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Oct. 01, 2024
Income Taxes Summary [Line Items]
Deferred tax assets	$ 2,979	$ 2,691
Valuation allowance	(344)	(343)
Income taxes receivable	83	32
Uncertain tax positions that would impact effective tax rate	31
Unrecognized tax benefits, accrued liabilities	2	$ 1
State and local
Income Taxes Summary [Line Items]
Operating loss carryforwards	$ 4,818
Southwestern
Income Taxes Summary [Line Items]
Deferred tax liabilities			$ 479
Southwestern \| Base $2 Million Annual Limitation
Income Taxes Summary [Line Items]
Deferred tax assets, operating loss carryforward, limitations			2
Southwestern \| Base $48 Million Annual Limitation
Income Taxes Summary [Line Items]
Deferred tax assets, operating loss carryforward, limitations			48
Southwestern \| Base $269 Million annual limitation
Income Taxes Summary [Line Items]
Deferred tax assets, operating loss carryforward, limitations			$ 269

Other Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Other Liabilities Disclosure [Abstract]

Schedule of Other Current Liabilities

Other current liabilities as of December 31, 2025 and 2024 are detailed below:


	December 31, 2025		December 31, 2024
Revenues and royalties due to others	$	972	$	734
Accrued drilling and production costs	350		296

Accrued compensation and benefits	107		124
Taxes payable	157		142
Operating leases	51		71
Joint interest prepayments received	11		13
Contract liabilities	253		284
Other	144		122
Total other current liabilities	$	2,045	$	1,786

Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 09, 2026	Oct. 01, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Feb. 17, 2026	Oct. 22, 2024	Jun. 30, 2022	Dec. 02, 2021	Feb. 09, 2021
Class of Stock [Line Items]
Common stock, shares issued (in shares)			239,249,874	231,769,886
Authorized amount							$ 1,000	$ 2,000	$ 1,000
Stock repurchased (in shares)			900,000	0	4,400,000
Additional authorized amount								$ 1,000
Stock repurchased			$ 100		$ 357
Number of shares issuable upon exercise each warrant			1.22
Subsequent Event
Class of Stock [Line Items]
Dividends payable (in dollars per share)						$ 0.575
Class A Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share)			$ 21.89							$ 27.63
Class B Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share)			25.45							32.13
Class C Warrants
Class of Stock [Line Items]
Warrant, exercise price (in dollars per share)			$ 28.66							$ 36.18
Common Stock
Class of Stock [Line Items]
Issuance of common stock for Southwestern Merger (in shares)				95,700,325
Number of shares initially exercisable for class of warrant or right (in shares)										1
Reserved Shares For General Unsecured Claims
Class of Stock [Line Items]
Common stock, shares issued (in shares)			295,255	468,723	12,089
Warrant
Class of Stock [Line Items]
Conversion of stock, shares issued (in shares)			7,497,509	4,083,103	221,952
Warrant \| Subsequent Event
Class of Stock [Line Items]
Conversion of stock, shares issued (in shares)	1,122,179
Southwestern \| Common Stock
Class of Stock [Line Items]
Issuance of common stock for Southwestern Merger (in shares)		95,700,325

Share-Based Compensation - Assumptions (Details) - Performance shares - TSR, rTSR	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	4.00%	4.55%	3.85%
Volatility	33.40%	39.36%	64.40%

- 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

Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Mar. 31, 2025	Dec. 31, 2024	Dec. 02, 2024	Oct. 28, 2024	Oct. 01, 2024
Long-term Debt [Abstract]
Outstanding borrowings	$ 5,025
Premiums (discounts) on senior notes, net	(8)		$ 4
Debt issuance costs	(8)		(10)
Total debt, net	5,009		5,680
Less current maturities of long-term debt, net	0		(389)
Long-term debt, net	5,009		5,291
Fair Value	5,063		5,548
Less current maturities of long-term debt, net	0		(389)
Total long-term debt, net	5,063		5,159
Credit facility \| 2025 Credit Facility
Long-term Debt [Abstract]
Borrowings	0		0
Fair Value	0		0
Credit facility \| Prior Credit Facility
Long-term Debt [Abstract]
Borrowings	0		0
Fair Value	0		0
Senior notes \| 4.95% senior notes due 2025
Long-term Debt [Abstract]
Outstanding borrowings	0		389
Fair Value	$ 0		389
Interest rate, stated percentage	4.95%					4.95%
Senior notes \| 5.50% senior notes due 2026
Long-term Debt [Abstract]
Outstanding borrowings	$ 0		47
Fair Value	$ 0		47
Interest rate, stated percentage	5.50%	5.50%			5.50%
Senior notes \| 5.375% senior notes due 2029
Long-term Debt [Abstract]
Outstanding borrowings	$ 638		700
Fair Value	$ 639		684
Interest rate, stated percentage	5.375%					5.375%
Senior notes \| 5.875% senior notes due 2029
Long-term Debt [Abstract]
Outstanding borrowings	$ 440		500
Fair Value	$ 441		494
Interest rate, stated percentage	5.875%				5.875%
Senior notes \| 6.75% senior notes due 2029
Long-term Debt [Abstract]
Outstanding borrowings	$ 847		950
Fair Value	$ 852		959
Interest rate, stated percentage	6.75%				6.75%	6.75%
Senior notes \| 5.375% senior notes due 2030
Long-term Debt [Abstract]
Outstanding borrowings	$ 1,200		1,200
Fair Value	$ 1,218		1,174
Interest rate, stated percentage	5.375%					5.375%
Senior notes \| 4.75% senior notes due 2032
Long-term Debt [Abstract]
Outstanding borrowings	$ 1,150		1,150
Fair Value	$ 1,137		1,067
Interest rate, stated percentage	4.75%					4.75%
Senior notes \| 5.70% senior notes due 2035
Long-term Debt [Abstract]
Outstanding borrowings	$ 750		750
Fair Value	$ 776		$ 734
Interest rate, stated percentage	5.70%			5.70%

Debt (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Our long-term debt consisted of the following as of December 31, 2025 and 2024:


	December 31, 2025				December 31, 2024
	Carrying Amount		Fair Value(a)		Carrying Amount		Fair Value(a)
2025 Credit Facility	$	—	$	—	$	—	$	—
Prior Credit Facility	—		—		—		—
4.95% senior notes due 2025(b)	—		—		389		389
5.50% senior notes due 2026	—		—		47		47
5.375% senior notes due 2029(b)	638		639		700		684
5.875% senior notes due 2029	440		441		500		494
6.75% senior notes due 2029	847		852		950		959
5.375% senior notes due 2030(b)	1,200		1,218		1,200		1,174
4.75% senior notes due 2032(b)	1,150		1,137		1,150		1,067
5.70% senior notes due 2035(c)	750		776		750		734
Premiums (discounts) on senior notes, net	(8)		—		4		—
Debt issuance costs	(8)		—		(10)		—
Total debt, net	5,009		5,063		5,680		5,548
Less current maturities of long-term debt, net	—		—		(389)		(389)
Total long-term debt, net	$	5,009	$	5,063	$	5,291	$	5,159

____________________________________________

(c)On December 2, 2024, we issued $750 million of 5.70% senior notes. See further discussion below.

Schedule of Debt Maturities

The table below presents debt maturities as of December 31, 2025, excluding debt issuance costs, discounts and premiums:


	Total




2029	1,925
2030	1,200
Thereafter	1,900
Total debt	$	5,025

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
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Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
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-Paragraph 4
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Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
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+ Details

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2025

Supplemental Cash Flow Information [Abstract]

Schedule of Supplemental Disclosures to the Consolidated Statements of Cash Flows

Supplemental disclosures to the consolidated statements of cash flows are presented below.


	Years Ended December 31,
	2025		2024		2023
Changes in assets and liabilities
Accounts receivable	$	(370)	$	(168)	$	857
Accounts payable	(68)		(62)		(152)
Other current assets	(40)		3		143
Other current liabilities	193		(88)		(573)
Total	$	(285)	$	(315)	$	275

Supplemental cash flow information:
Interest paid, net of capitalized interest	$	230	$	93	$	117
Income taxes paid (refunds received), net
Federal	$	80	$	7	$	120
State(a)	$	(14)	$	(10)	$	12
Total	$	66	$	(3)	$	132

Supplemental disclosure of significant non-cash investing and financing activities:
Change in accrued drilling and completion costs	$	114	$	(49)	$	(31)
Common stock issued for business combination	$	—	$	7,888	$	—
Operating lease obligations recognized	$	39	$	137	$	96
Liabilities established in connection with property acquisitions	$	29	$	—	$	—

_________________________________________

(a)Income taxes paid (refunds received), net by state is provided below. Amounts reported within other states below include states that are individually below the reporting threshold.


	Years Ended December 31,
	2025		2024		2023
State

Louisiana	$	(15)	$	(1)	$	12
New York	1		—		—
Pennsylvania	(1)		(10)		—
Texas	—		2		—
West Virginia	1		—		—

Other states	—		(1)		—
Total	$	(14)	$	(10)	$	12