10-K – 2026-02-18 – exe-20251231.htm

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 loa ns. 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
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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.
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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.

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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.
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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.
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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  

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  

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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  

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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  

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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  

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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  

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.
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.
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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
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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.
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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.
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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.
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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 no t 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.
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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  
_________________________________________
(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.
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 approximatel y 1.93 years.
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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 approximatel y $ 26  million of total unrecognized compensation expense related to unvested PSUs. The expense is expected to be recognized over a weighted average period of approximat ely 2.03 years .
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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  

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.

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.

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• 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 )

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Effect of Derivative Instruments – 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.
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 no t have any cash or letters of credit posted as collateral for our commodity derivatives.
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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.

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 no t recognized any impairments related to our investment with Momentum.
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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.

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.
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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  

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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 no t 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.

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SUPPLEMENTARY INFORMATION

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.
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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
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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  

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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.
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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.
(c)    Calculated using prices of $ 2.64 per Mcf of natural gas, 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.
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(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.
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Interim Chief Executive Officer and Interim Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Interim Chief Executive Officer and Interim Chief Financial Officer concluded as of December 31, 2025 that our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Expand Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's  Internal Control-Integrated Framework  (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2025.
The effectiveness of our internal control over financial reporting as of December 31, 2025 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.

/s/ MICHAEL A. WICHTERICH
Michael A. Wichterich
Chairman of the Board, Interim President and Chief Executive Officer

/s/ BRITTANY RAIFORD
Brittany Raiford
Vice President, Interim Chief Financial Officer and Treasurer

February 18, 2026

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Item 9B. Other Information

Rule 10b5-1 Trading Arrangements
During the three months ended December 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement”, as each term is defined in Item 408 of Regulation S-K.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The names of executive officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Expand Energy pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2025 (the “2026 Proxy Statement”).
Code of Business Conduct
The Company has adopted a Code of Business Conduct that applies to all of its officers, directors and employees. We have posted a copy of our Code of Business Conduct on the “Sustainability” section of our website at www.expandenergy.com. Any amendments to, or waivers from, our Code of Business Conduct that apply to our executive officers and directors will be posted on the “Sustainability” section of our website at www.expandenergy.com. Note that the information on the Company’s website is not incorporated by reference into this filing.

Item 11. Executive Compensation

The information called for by this Item 11 is incorporated herein by reference to the 2026 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by this Item 12 is incorporated herein by reference to the 2026 Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information called for by this Item 13 is incorporated herein by reference to the 2026 Proxy Statement.

Item 14. Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated herein by reference to the 2026 Proxy Statement.
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PART IV

Item 15. Exhibits and Financial Statement Schedules

____________________________________________
(a)    The following financial statements, financial statement schedules and exhibits are filed as a part of this report:
1. Financial Statements . Expand Energy's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
2. Financial Statement Schedules . No financial statement schedules are applicable or required.
3. Exhibits . The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS

    Incorporated by Reference  
Exhibit
Number
Exhibit Description Form SEC File
Number
Exhibit Filing Date Filed or
Furnished
Herewith

2.1 Fifth Amended Joint Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates Pursuant to Chapter 11 of the Bankruptcy Code (Exhibit A of the Confirmation Order).
8-K 001-13726 2.1 1/19/2021

2.2* Agreement and Plan of Merger, dated as of January 10, 2024, among Chesapeake Energy Corporation, Hulk Merger Sub, Inc., Hulk LLC Sub, LLC, and Southwestern Energy Corporation
8-K 001-13726 2.1 1/11/2024

3.1 Third Amended and Restated Certificate of Incorporation of Expand Energy Corporation.
8-K 001-13726 3.1 10/1/2024

3.2
Third Amended and Restated Bylaws of Expand Energy Corporation.
8-K 001-13726 3.2 10/1/2024

4.1
Description of Securities.
8-A 001-13726 N/A 2/9/2021

10.1
Restructuring Support Agreement, dated June 28, 2020.
8-K 001-13726 10.1 6/29/2020

10.2
Backstop Commitment Agreement, dated June 28, 2020 (Exhibit 4 to the Restructuring Support Agreement).
8-K 001-13726 10.1 6/29/2020

10.3
Registration Rights Agreement, dated as of February 9, 2021, by and among Chesapeake Energy Corporation and the other parties signatory thereto.
8-K 001-13726 10.2 2/9/2021

10.4
Class A Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K 001-13726 10.3 2/9/2021

10.5
Class B Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K 001-13726 10.4 2/9/2021

10.6
Class C Warrant Agreement, dated as of February 9, 2021, between Chesapeake Energy Corporation and Equiniti Trust Company.
8-K 001-13726 10.5 2/9/2021

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10.7 Form of Indemnity Agreement.
10-K 001-13726 10.7 2/26/2025

10.8† Expand Energy Corporation 2021 Long Term Incentive Plan.
10-K 001-13726 10.8 2/26/2025

10.9 Purchase Agreement, dated as of February 2, 2021, by and among Chesapeake Escrow Issuer LLC, and Goldman Sachs & Co. LLC, RBC Capital Markets, LLC, as representatives of the purchasers signatory thereto, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K 001-13726 10.10 3/1/2021

10.10 Indenture dated as of February 5, 2021, among Chesapeake Escrow Issuer LLC, as issuer, the guarantors signatory thereto, and Deutsche Bank Trust Company Americas, as Trustee, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K 001-13726 10.11 3/1/2021

10.11 Joinder Agreement, dated as of February 9, 2021, by and among Chesapeake Energy Corporation and the Guarantors party thereto, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K 001-13726 10.12 3/1/2021

10.12 First Supplemental Indenture, dated as of February 9, 2021, by and among Chesapeake Energy Corporation, the Guarantors signatory thereto, and Deutsche Bank Trust Company Americas, as Trustee, with respect to 5.5% Senior Notes due 2026 and 5.875% Senior Notes due 2029.
10-K 001-13726 10.13 3/1/2021

10.13† Amendment to the Expand Energy Corporation 2021 Long Term Incentive Plan.
10-K 001-13726 10.13 2/26/2025

10.14† Form of Executive/Employee Restricted Stock Unit Award Agreement for Expand Energy Corporation 2021 Long Term Incentive Plan.
X

10.15† Form of Non-Employee Director Restricted Stock Unit Award Agreement for Expand Energy Corporation 2021 Long Term Incentive Plan.
10-K 001-13726 10.15 2/26/2025

10.16† Form of Performance Share Unit Award (Absolute TSR) for Expand Energy Corporation 2021 Long Term Incentive Plan.
X

10.17† Form of Performance Share Unit Award (Relative TSR) for Expand Energy Corporation 2021 Long Term Incentive Plan.
X

10.18† Expand Energy Corporation Executive Severance Plan.
10-K 001-13726 10.18 2/26/2025

10.19† Form of Participation Agreement pursuant to Expand Energy Corporation Executive Severance Plan.
10-K 001-13726 10.19 2/26/2025

10.20† Form of Interim Chief Executive Officer Restricted Stock Unit Award Agreement for Expand Energy Corporation 2021 Long Term Incentive Plan.
X

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10.21† Form of Interim Chief Executive Officer Performance Share Unit Award (Absolute TSR) for Expand Energy Corporation 2021 Long Term Incentive Plan.
X

10.22† Second Amendment to the Expand Energy Corporation 2021 Long Term Incentive Plan.
10-K 001-13726 10.20 2/26/2025

10.23 Supplemental Indenture, dated as of November 2, 2021, by and among Chesapeake Energy Corporation, the guarantors party thereto and Wilmington Trust, National Association, as Trustee.
8-K 001-13726 4.1 11/2/2021

10.24 Supplemental Indenture, dated as of November 2, 2021, by and among Chesapeake Energy Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as Trustee.
8-K 001-13726 4.2 11/2/2021

10.25 Registration Rights Agreement dated March 9, 2022, by and among the Company and The Jan & Trevor Rees-Jones Revocable Trust, Rees-Jones Family Holdings, LP, Chief E&D Participants, LP, and Chief E&D (GP) LLC.
8-K 001-13726 10.1 3/9/2022

10.26 Registration Rights Agreement dated March 9, 2022, by and among the Company and Radler 2000 Limited Partnership.
8-K 001-13726 10.2 3/9/2022

10.27 Form of Dealer Manager Agreement in connection with exchange offers for Warrants.

S-4 333-266961 10.34 8/18/2022

10.28 Form of Tender and Support Agreement, dated September 12, 2022, in connection with exchange offers for Warrant.

S-4/A 333-266961 10.35 9/12/2022

10.29† Form of Chesapeake Energy Corporation Executive Letter Agreement
8-K 001-13726 10.1 1/11/2024

10.30† Letter Agreement with Chris Lacy, dated October 11, 2024.
10-K 001-13726 10.29 2/26/2025

10.31 Indenture, dated as of December 2, 2024, by and between Expand Energy Corporation and Regions Bank, as Trustee.
8-K 001-13726 4.1 12/2/2024

10.32 First Supplemental Indenture, dated as of December 2, 2024, by and between Expand Energy Corporation and Regions Bank, as Trustee (including the form of the Notes).
8-K 001-13726 4.2 12/2/2024

10.33 Agreement No. 1 and Borrowing Base Agreement, dated as of April 29, 2024, among Chesapeake Energy Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders and other parties thereto.
10-Q 001-13726 10.1 7/29/2024

10.34 Credit Agreement, dated as of December 9, 2022 by and among Expand Energy Corporation (f/k/a Chesapeake Energy Corporation), the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent
8-K 001-13726 10.1 11/1/2024

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10.35 Amended and Restated Credit Agreement, dated as of September 30, 2025, by and among Expand Energy Corporation, the financial institutions from time to time party thereto as lenders and JPMorgan Chase Bank, N.A., as Administrative Agent
8-K 001-13726 10.1 9/30/2025

10.36† Global Supplement to Awards under the Expand Energy Corporation 2021 Long Term Incentive Plan
10-K 001-13726 10.34 2/26/2025

19.1 Expand Energy Corporation Insider Trading Compliance Policy
10-K 001-13726 19.1 2/26/2025

21 Subsidiaries of Expand Energy Corporation.
X

23.1 Consent of PricewaterhouseCoopers LLP.
X

23.2 Consent of Netherland, Sewell & Associates, Inc.
X

24 Power of Attorney (included as a part of the signature pages to this report). X

31.1 Michael Wichterich, Chairman of the Board, Interim President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
X

31.2 Brittany Raiford, Vice President, Interim Chief Financial Officer and Treasurer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
X

32.1** Michael Wichterich, Chairman of the Board, Interim President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X

32.2** Brittany Raiford, Vice President, Interim Chief Financial Officer and Treasurer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
X

95.1 Mine Safety Disclosures
X

97.1 Expand Energy Corporation Clawback Policy
10-K 001-13726 97.1 2/26/2025

99.1 Audit Letter of Netherland, Sewell & Associates, Inc.
X

101 INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. X

101 SCH Inline XBRL Taxonomy Extension Schema Document. X

101 CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document. X

101 DEF Inline XBRL Taxonomy Extension Definition Linkbase Document. X

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101 LAB Inline XBRL Taxonomy Extension Labels Linkbase Document. X

101 PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document. X

104 Cover Page Interactive Data file (formatted as Inline XBRL and contained in Exhibit 101). X

*
Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.
** Furnished herewith.
†
Management contract or compensatory plan or arrangement.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about Expand Energy Corporation or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in our public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about Expand Energy Corporation or its business or operations on the date hereof.

Item 16. Form 10-K Summary

Not applicable.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EXPAND ENERGY CORPORATION

Date: February 18, 2026
By:   /s/ MICHAEL A. WICHTERICH
    Michael A. Wichterich
Chairman of the Board, Interim President and Chief Executive Officer

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POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Michael A. Wichterich his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Capacity Date
/s/ MICHAEL A. WICHTERICH Chairman of the Board, Interim President and Chief Executive Officer
(Principal Executive Officer)
February 18, 2026
Michael A. Wichterich

/s/ BRITTANY RAIFORD Vice President, Interim Chief Financial Officer and Treasurer
(Principal Financial Officer)
February 18, 2026
Brittany Raiford

/s/ GREGORY M. LARSON Vice President - Accounting & Controller
(Principal Accounting Officer)
February 18, 2026
Gregory M. Larson

/s/ TIMOTHY S. DUNCAN Director February 18, 2026
Timothy S. Duncan

/s/ BENJAMIN C. DUSTER, IV Director February 18, 2026
Benjamin C. Duster, IV

/s/ SARAH A. EMERSON Director February 18, 2026
Sarah A. Emerson

/s/ MATTHEW M. GALLAGHER Director February 18, 2026
Matthew M. Gallagher

/s/ JOHN D. GASS Director February 18, 2026
John D. Gass

/s/ SYLVESTER P. JOHNSON IV Director February 18, 2026
Sylvester P. Johnson IV

/s/ CATHERINE A. KEHR Director February 18, 2026
Catherine A. Kehr

/s/ SHAMEEK KONAR Director February 18, 2026
Shameek Konar

/s/ BRIAN STECK Director February 18, 2026
Brian Steck

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